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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ____________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD PRC-012-2
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Shamai Elstein
Senior Counsel
Andrew C. Wills
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
August 5, 2016
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
II.
NOTICES AND COMMUNICATIONS ................................................................................ 5
III. BACKGROUND .................................................................................................................... 6
A.
Regulatory Framework ..................................................................................................... 6
B.
NERC Reliability Standards Development Procedure ..................................................... 7
C.
Procedural History of Reliability Standard PRC-012-2 ................................................... 8
IV. JUSTIFICATION FOR APPROVAL................................................................................... 11
V.
A.
Applicability ................................................................................................................... 13
B.
Requirement by Requirement Justification .................................................................... 14
i)
Requirements R1, R2, and R3 .................................................................................... 15
ii)
Requirement R4 .......................................................................................................... 18
iii)
Requirement R5 .......................................................................................................... 29
iv)
Requirements R6 and R7 ............................................................................................ 31
v)
Requirement R8 .......................................................................................................... 34
vi)
Requirement R9 .......................................................................................................... 36
C.
Enforceability of Proposed Reliability Standard PRC-012-2 ........................................ 38
D.
Proposed Retirements and Withdrawals ........................................................................ 40
i)
Reliability Standard PRC-012-1 ................................................................................. 40
ii)
Reliability Standard PRC-013-1 ................................................................................. 42
iii)
Reliability Standard PRC-014-1 ................................................................................. 43
iv)
Reliability Standards PRC-015-1 and PRC-016-1 ..................................................... 43
EFFECTIVE DATE .............................................................................................................. 45
VI. CONCLUSION ..................................................................................................................... 48
Exhibit A
Examples of WECC Local Area Protection Systems (LAPS) and NPCC Type III
Remedial Action Schemes
Exhibit B
Proposed Reliability Standard PRC 012-2
Exhibit C
Implementation Plan for PRC-012-2
Exhibit D
Analysis of Violation Risk Factors and Violation Severity Levels for
Reliability Standard PRC-012-2
Exhibit E
Mapping Document for PRC-012-2
Exhibit F
Reliability Standard PRC-12-2 Remedial Action Schemes Question & Answer
Document
Exhibit G
Order No. 672 Criteria
Exhibit H
Summary of Development History and Complete Record of Development
Exhibit I
Standard Drafting Team Roster
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ____________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD PRC-012-2
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 the
North American Electric Reliability Corporation (“NERC”) 3 hereby requests Commission
approval of the following 4:
•
Reliability Standard PRC-012-2 (Remedial Action Schemes) (Exhibit B);
•
retirement of currently effective Reliability Standards PRC-015-1 (Remedial Action
Scheme Data and Documentation) and PRC-016-1 (Remedial Action Scheme
Misoperation);
•
withdrawal of Reliability Standards PRC-012-1 (Remedial Action Scheme Review
Procedure), PRC-013-1 (Special Protection System Database), and PRC-014-1 (Remedial
Action Scheme Assessment); 5
1
16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2016).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the Federal Power Act on July 20, 2006 in Docket No. RR06-1-000. See Order Certifying North
American Electric Reliability Corporation as the Electric Reliability Organization and Ordering Compliance Filing,
116 FERC ¶ 61,062 (2006), order on reh’g and compliance, 117 FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa Inc. v.
FERC, 564 F.3d 342 (D.C. Cir. 2009).
4
Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of
Terms Used in NERC Reliability Standards (“NERC Glossary”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.
5
NERC notes that the Commission has never approved or remanded the original versions of Reliability
Standards RPC-012-0, PRC-013-0, and PRC-014-0, as the Commission deemed these standards “fill-in-the-blank”
standards in Order No. 693. See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC
Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007). In its petition for approval of
the revised definition of Remedial Action Scheme submitted on February 3, 2015, NERC submitted a new version
of these standards but did not request Commission approval of these standards. Rather, NERC noted that it was
submitting Reliability Standards PRC-012-1, PRC-013-1, and PRC-014-1 “for completeness.” Petition of the North
American Electric Reliability Corporation for Approval of Revisions to the Definition of “Remedial Action Scheme”
and Proposed Reliability Standards, Docket No. RM15-13-000 at n. 6, 7, 8 (Feb. 3, 2015).
2
1
•
Implementation Plan for PRC-012-2 (Exhibit C); and
•
associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for
PRC-012-2 (Exhibits D) (collectively, “NERC’s Proposal”).
NERC’s Proposal was developed in Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (“Project”) and addresses all aspects of the design, approval,
installation, and maintenance of Remedial Action Schemes (“RAS”). The NERC Board of
Trustees adopted proposed Reliability Standard PRC-012-2, retirement of Reliability Standards
PRC-015-1 (Remedial Action Scheme Data and Documentation) and PRC-016-1 (Remedial
Action Scheme Misoperation), and withdrawal of previously unapproved Reliability Standards
PRC-012-1 (Remedial Action Scheme Review Procedure), PRC-013-1 (Special Protection
System Database), and PRC-014-1 (Remedial Action Scheme Assessment) on May 5, 2016.
NERC requests that the Commission approve NERC’s Proposal as just, reasonable, not
unduly discriminatory or preferential, and in the public interest. As required by Section 39.5(a)
of the Commission’s regulations, 6 this Petition presents the technical basis and purpose of
proposed Reliability Standard PRC-012-2, a summary of the development history and the
complete record of development (Exhibit H), and a demonstration that the proposed Reliability
Standard meets the criteria identified by the Commission in Order No. 672 (Exhibit G). 7
I.
EXECUTIVE SUMMARY
RAS are, by definition, critical to preserving the reliability and integrity of the Bulk
Electric System (“BES”), as they operate to institute “corrective actions that may include, but are
6
18 C.F.R. § 39.5(a) (2016).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at PP 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
7
2
not limited to, adjusting or tripping generation (MW and Mvar), tripping load, or reconfiguring a
System(s).” 8 The purpose of a RAS is to mitigate unacceptable System conditions subsequent to
fault clearing, thereby reducing the risk of instability. Each RAS is unique in its location, design,
and application, yet each RAS must be coordinated with other RAS and protection and control
systems to govern BES reliability. Given the need for coordination of RAS, entities with a widearea operational visibility must oversee the design, approval, installation, and maintenance of
these important elements of the interconnected transmission network. In addition, entities with
operational knowledge of RAS must perform routine tests after the operation or misoperation of
a RAS to confirm its continued efficacy. Proposed Reliability Standard PRC-012-2, developed
in Project 2010-05.3, addresses these considerations.
The standard drafting team for Project 2010-05.3 (“RAS SDT”) developed proposed
Reliability Standard PRC-012-2 by combining currently effective Reliability Standards PRC015-1 and PRC-016-1 and unapproved Reliability Standards PRC-012-1, PRC-013-1, and PRC014-1 into a single, consolidated, continent-wide Reliability Standard to address all aspects of
RAS. Proposed Reliability Standard PRC-012-2 improves upon the existing standards as it
removes ambiguity in NERC’s original “fill-in-the-blank” standard by assigning responsibility to
appropriate functional entities. The proposed standard also streamlines and consolidates the
“piecemeal” RAS standards into one clear, effective Reliability Standard.
Specifically, proposed PRC-012-2 implements a centralized review process for each new
or functionally modified RAS; obligates entities to complete periodic evaluations, tests, and
operational analyses for all RAS; and requires the entity with a wide-area view to establish a
8
NERC Glossary (updated on June 24, 2016) at 84, available at
http://www.nerc.com/files/glossary_of_terms.pdf.
3
database with pertinent information about each RAS. In doing so, the proposed standard vests
the responsibility to administer the RAS review process and to create the RAS database with the
Reliability Coordinator (“RC”). The standard requires the RAS-entity, which is the entity that
“owns all or part of a RAS,” 9 to submit RAS information to the RC for review, address
reliability issues identified by the RC, analyze operational performance of each RAS, and
perform periodic functional tests of each RAS. Finally, the standard requires the Planning
Coordinator (“PC”) to periodically evaluate each RAS within its area to verify the continued
effectiveness and coordination of the RAS. Proposed Reliability Standard PRC-012-2
establishes these obligations in nine requirements, as follows:
9
•
Requirement R1 requires RAS-entities to submit certain information about each RAS that
it intends to place into service to the RC where the RAS is located.
•
Requirement R2 requires RCs that receive information about a RAS from a RAS-entity to
review the RAS and provide feedback to the RAS-entity.
•
Requirement R3 requires the RAS-entity that receives feedback from the RC regarding its
RAS to resolve each reliability issue to obtain approval of the RAS from the RC.
•
Requirement R4 requires the PC to perform a periodic evaluation of each RAS within its
planning area, according to the type of RAS being evaluated.
•
Requirement R5 requires each RAS-entity to perform an analysis of each RAS after
operation or misoperation of the RAS and to provide the results of the evaluation to the
reviewing RC.
•
Requirement R6 requires the RAS-entity to develop and submit a Corrective Action Plan
(“CAP”) to the reviewing RC after learning of a deficiency with its RAS.
•
Requirement R7 requires the RAS-entity to implement the CAP, update the CAP as
necessary, and notify the RC when any changes are made to the CAP and when the CAP
has been fulfilled.
•
Requirement R8 requires the RAS-entity to test its RAS to verify continued operation on
a timeline according to the type of RAS that is being tested.
RAS-entities include Transmission Owners, Generator Owners, and Distribution Providers.
4
•
Requirement R9 requires the RC to update its RAS database with information about each
RAS on a yearly basis.
As explained in more detail below, proposed Reliability Standard PRC-012-2 integrates
seamlessly with other relevant Reliability Standards and does not upend the established
performance requirements in Reliability Standard TPL-001-4. Further, the proposed standard
identifies a subset of RAS called “limited impact RAS” that represent those RAS that cannot “by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably dampened
oscillations.” 10 The proposed standard imposes more focused review requirements on RAS that
have greater BES reliability impact and unique design.
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to: 11
Shamai Elstein*
Senior Counsel
Andrew C. Wills*
Associate Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
10
Howard Gugel*
Director of Standards
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
[email protected]
See Proposed Reliability Standard PRC-012-2 at 7, 21 (attached herein as Exhibit B).
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2016), to allow the inclusion
of more than two persons on the service list in this proceeding.
11
5
III.
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005, 12 Congress entrusted the Commission 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 Electric Reliability Organization (“ERO”) that
would be charged with developing and enforcing mandatory Reliability Standards, subject to
Commission approval. Section 215(b)(1) of the FPA states that all users, owners, and operators
of the Bulk-Power System in the United States will be subject to Commission-approved
Reliability Standards. 13 Section 215(d)(5) of the FPA authorizes the Commission to order the
ERO to submit a new or modified Reliability Standard. 14 Section 39.5(a) of the Commission’s
regulations requires the ERO to file with the Commission 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. 15
The Commission is vested with the regulatory responsibility to approve Reliability
Standards that protect the reliability of the Bulk-Power System and to ensure that such
Reliability Standards are just, reasonable, not unduly discriminatory or preferential, and in the
public interest. The Commission also exercises oversight regarding proposals to retire Reliability
Standards. 16 Pursuant to Section 215(d)(2) of the FPA 17 and Section 39.5(c) of the
12
13
14
15
16
17
16 U.S.C. § 824o (2012).
Id. § 824o(b)(1).
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
See e.g., NERC Standards Processes Manual, at Section 4.19 of the NERC Rules of Procedure.
16 U.S.C. § 824o(d)(2).
6
Commission’s regulations, “the Commission will give due weight to the technical expertise of
the Electric Reliability Organization” with respect to the content of a Reliability Standard. 18
B.
NERC Reliability Standards Development Procedure
NERC’s Proposal was developed in an open and fair manner and in accordance with the
Commission-approved Reliability Standard development process. 19 NERC develops Reliability
Standards in accordance with Section 300 (Reliability Standards Development) and Appendix
3D (NERC Standard Processes Manual) of the Commission approved NERC Rules of
Procedure. 20
In its order certifying NERC as the Commission’s ERO, the Commission found that
NERC’s proposed rules provide for reasonable notice and opportunity for public comment, due
process, openness, and a balance of interests in developing Reliability Standards, 21 and thus
satisfy certain of the criteria for approving Reliability Standards. 22 The ANSI-accredited
development process is open to any person or entity with a legitimate interest in the reliability of
the Bulk-Power System. NERC considers the comments of all stakeholders, and stakeholders
must approve, and the NERC Board of Trustees must adopt a Reliability Standard before NERC
submits the Reliability Standard to the Commission for approval.
18
18 C.F.R. § 39.5(c)(1).
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“Further, in considering
whether a proposed Reliability Standard meets the legal standard of review, we will entertain comments about
whether the ERO implemented its Commission-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.”).
20
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
21
116 FERC ¶ 61,062 at P 250.
22
Order No. 672 at PP 268, 270.
19
7
C.
Procedural History of Reliability Standard PRC-012-2
In Order No. 693, the Commission evaluated 107 Reliability Standards, including
Reliability Standards PRC-012-0 (Special Protection System Review Procedure), PRC-013-0
(Special Protection System Database), PRC-014-0 (Special Protection System Assessment),
PRC-015-0 (Special Protection System Data and Documentation), and PRC-016-0 (Special
Protection System Misoperations). 23 While the Commission approved Reliability Standard
PRC-015-0 and PRC-016-0 as mandatory and enforceable in Order No. 693, the Commission
neither approved nor remanded Reliability Standards PRC-012-0, PRC-013-0, and PRC-014-0
but identified these as “fill-in-the-blank” standards with an inadequate basis for approval. 24
Along with the abovementioned standards, the Commission also approved the NERC Glossary,
which included definitions for the terms “Special Protection System” (“SPS”) and “Remedial
Action Scheme.” 25 As these terms were used interchangeably across Interconnections and the
ERO Regions, NERC developed the definitions approved in Order No. 693 to ensure that both
terms could be used in reference to the same equipment.
In early 2010, after several years’ experience implementing these standards and based on
industry input, NERC initiated Project 2010-05 to address issues associated with RAS and SPS.
NERC initiated the project to address the inconsistent usage of the terms RAS and SPS across
Interconnections and NERC Regions, and to modify the standards to improve the monitoring of
BES Protection System events by identifying and correcting the causes of Misoperations. Based
on industry input, NERC subdivided the work in Project 2010-05 into two phases, Project 2010-
23
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶
31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
24
Id. at PP 1520, 1524, 1528, 1533, and 1539.
25
Id. at P 1893.
8
05.1 and Project 2010-05.2, to address issues associated with Misoperations of Protection
Systems ahead of the work associated with SPS and RAS. 26 The work in Project 2010-05.1
culminated in the development of proposed Reliability Standard PRC-004-3 (Protection System
Misoperation Identification and Correction) and the proposed revised definition of
“Misoperations.” On September 15, 2014, NERC submitted proposed Reliability Standard PRC004-3 (Protection System Misoperation Identification and Correction) and the NERC Glossary
definition for the term “Misoperations” to the Commission in Docket No. RD14-14-000. 27 The
Commission approved PRC-004-3 and the definition of Misoperations on May 13, 2015. 28
While work on Misoperations continued in Project 2010-05.1, NERC simultaneously
began its effort to improve the identification and assessment of SPS and RAS in Project 201005.2. In the Standards Authorization Request for Project 2010-05.2, NERC stated that the
project would address the RAS and SPS definitions, the Commission’s Order No. 693 findings,
and four recommendations related to the “identification and coordination of SPS from the joint
FERC-NERC inquiry of the September 2011 Southwest Blackout Event.” 29 In the initial stages
of development for this project, NERC realized the extent of the work necessary to revise
associated definitions and Reliability Standards and to develop a consistent, uniform, and
continent-wide RAS-specific Reliability Standard, and further divided Project 2010-05.2 into
26
See NERC Standards Committee Meeting Minutes (Jun. 9, 2011), available at
http://www.nerc.com/docs/standards/sc/sc_060911m_package.pdf.
27
Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability
Standard PRC-004-3, Docket No. RD14-14-000 (filed on Sept. 15, 2014).
28
Order Approving Reliability Standard, 151 FERC ¶ 61,129 (May 13, 2015).
29
Standard Authorization Request for Project 2010-05.2 (Feb. 12, 2014), accessible online at
http://www.nerc.com/pa/Stand/Prjct201005_2SpclPrtctnSstmPhs2/SPS_SAR_02042014.pdf (explaining that the
project would address the Commission’s decision in Order No. 693 to neither approve nor remand Reliability
Standards PRC-012-0, PRC-013-0, and PRC-014-0, and that the project would address four recommendations from
the FERC-NERC inquiry of the September 2011 Southwest Blackout Event. Notably, the recommendations from
the FERC-NERC inquiry, which were related to the identification and coordination of SPS, were addressed during
the development of the revised definition of RAS, submitted to the Commission in Docket No. RM15-13-000.).
9
two projects. NERC commenced development in these projects, Project 2010-05.2 and Project
2010-05.3, to revise the definition of RAS and to develop a Reliability Standard addressing
issues associated with RAS, respectively.
In 2011, NERC began development of a revised definition of RAS in Project 2010-05.2
based on the findings of a System Protection and Control Subcommittee (“SPCS”) and System
Analysis and Modeling Subcommittee (“SAMS”) Technical Report titled “Special Protection
Systems (SPS) and Remedial Action Schemes (RAS): Assessment of Definition, Regional
Practices, and Application of Related Standards” (“SPCS/SAMS Report”). 30 The SPCS/SAMS
Report noted the lack of clarity of the definition of SPS, the inconsistent use of the terms SPS
and RAS across the eight Regions, and the impact this inconsistent usage would have on
identification. Using the information in the SPCS/SAMS Report, the standard drafting team for
Project 2010-05.2 developed an improved, revised definition of RAS with more detail than the
existing definition of SPS, including a refined core definition and specific inclusions and
exclusions. NERC submitted the revised definition and several revised Reliability Standards
incorporating the new term, including Reliability Standards PRC-015-1 and PRC-016-1, 31 on
February 3, 2015. 32 On November 19, 2015, the Commission issued Order No. 818 approving,
among other things, the revised RAS definition. 33
30
See Petition of the North American Electric Reliability Corporation for Approval of Revisions to the
Definition of “Remedial Action Scheme” and Proposed Reliability Standards (“RAS Petition”), Docket No. RM1513-000 at Exhibit G (filed on Feb. 3, 2015).
31
NERC notes that the only substantive revisions made in the revised standards, PRC-015-1 and PRC-016-1,
were to transition from use of the term “Special Protection System” to the newly defined term “Remedial Action
Scheme.”
32
RAS Petition at n. 6, 7, 8 (including revisions to Reliability Standards PRC-012-0, PRC-013-0, and PRC014-0 to incorporate the term “Remedial Action Scheme,” and noting that because the Commission neither approved
nor remanded these standards in Order No. 693, NERC was not requesting approval of these standards. Rather,
NERC noted that it was submitting Reliability Standards PRC-012-1, PRC-013-1, and PRC-014-1 “for
completeness.”).
33
Revisions to Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding
Reliability Standards; Revisions to the Definition of “Remedial Action Scheme” and Related Reliability Standards
(Order No. 818), 153 FERC ¶ 61,228 (2015).
10
NERC initiated Project 2010-05.3 in 2015 to address all other aspects of RAS and SPS in
the RAS/SPS-related Reliability Standards. The RAS SDT concluded its work with the
development of proposed Reliability Standard PRC-012-2 (Remedial Action Schemes), which is
the subject of this Petition, and a revised NERC Glossary definition of SPS. NERC developed
the revised definition of SPS to complete the transition from the term “Special Protection
System” to “Remedial Action Scheme” initiated by NERC in Project 2010-05.2. As industry
approved the revised definition of SPS before proposed PRC-012-2, NERC submitted the revised
definition of SPS to the Commission in a separate petition on May 11, 2016. 34 On June 23,
2016, the Commission issued a delegated letter order approving the revised definition of SPS. 35
Industry approved proposed Reliability Standard PRC-012-2 in a final ballot ending on
April 29, 2016. 36 The proposed standard, which addresses the implementation of all new and
functionally modified RAS as well as the periodic review of all in-service RAS, combines two
Commission approved standards and three previously unapproved standards deemed by the
Commission in Order No. 693 to be “fill-in-the-blank” standards. The NERC Board of Trustees
approved proposed Reliability Standard PRC-012-2 on May 5, 2016.
IV.
JUSTIFICATION FOR APPROVAL
NERC’s Proposal represents the technical findings of the RAS SDT based on its review
of the Commission’s findings related to SPS and RAS in Order No. 693, the recommendations
34
Petition of the North American Electric Reliability Corporation for Approval of the Revised Definition of
Special Protection System, Docket No. RD16-5-000 (May 11, 2016).
35
N. Am. Elec. Reliability Corp., Docket No. RD16-5-000 (June 23, 2016) (unpublished letter order).
36
See NERC, Standard Announcement, Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action
Schemes (RAS) PRC-12-2 and Definition of “Special Protection System, available at
http://www.nerc.com/pa/Stand/Prjct201005_3RmdialActnSchmsPhase3ofPrtctnSystmsDL/2010-05.3_PRC-0122_FB_Results_Word_Announce_05032016.pdf.
11
related to SPS and RAS from the FERC-NERC inquiry37 of the September 2011 Southwest
Blackout Event, several years’ experience monitoring and evaluating SPS and RAS, and
stakeholder comments throughout the Project. The purpose of proposed Reliability Standard
PRC-012-2 is to “[t]o ensure that [RAS] do not introduce unintentional or unacceptable
reliability risks to the [BES].” The nine Requirements of proposed PRC-012-2 accomplish the
stated purpose by addressing planning, coordination, design, review, assessment, and
documentation of each RAS. The proposed standard, which establishes a continent-wide RAS
review and maintenance program, should ensure that each RAS integrates seamlessly and
effectively into the BES and contributes to reliability by performing its intended function as
designed.
Proposed Reliability Standard PRC-012-2 is intended to supersede unapproved
Reliability Standards PRC-012-1, PRC-013-1, and PRC-014-1, as well as retire and replace
currently effective Reliability Standards PRC-015-1 and PRC-016-1. 38 NERC has developed a
concise comparison of the requirements of several currently effective and pending Reliability
Standards and the proposed Reliability Standard PRC-012-2 in the Mapping Document for PRC012-2, attached herein as Exhibit E. Proposed Reliability Standard PRC-12-2 represents
substantial improvements over these Reliability Standards, as it streamlines and consolidates
37
See Standards Authorization Request for Project 2010-05.2—Special Protection System (Feb. 12, 2014),
available at http://www.nerc.com/pa/Stand/Prjct201005_2SpclPrtctnSstmPhs2/SPS_SAR_02042014.pdf; see also
Arizona-Southern California Outages on September 8, 2011, Causes and Recommendations (April 2012), available
at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
38
For purposes of this Petition, NERC treats Reliability Standards PRC-012-1, PRC-013-1, and PRC-014-1
as if they were part of NERC’s original suite of Reliability Standards. These “version 1” Reliability Standards were
revised during the development of revisions to the term RAS by changing the term “Special Protection System” to
“Remedial Action Scheme.” While noting that the Commission would not approve Reliability Standards PRC-0121, PRC-013-1, and PRC-014-1, NERC submitted these standards to the Commission in the RAS Petition “for
completeness.” See RAS Petition at n. 6, 7, 8.
12
existing requirements, corrects the applicability of previously unapproved standards, and
implements a continent-wide RAS review program.
The following sections provide: (i) an explanation of the applicability of Reliability
Standard PRC-012-2, (ii) a requirement by requirement justification of each of the nine
Requirements in proposed Reliability Standard PRC-012-2, including an explanation for use of
the term “limited impact” RAS to account for the different impacts on reliability of those RAS,
and an explanation of the interplay between PRC-012-2 and TPL-001-4, (iii) a summary of the
enforceability of PRC-012-2, and (iv) a justification for the proposed retirements and
withdrawals associated with the development of PRC-012-2.
A.
Applicability
Proposed Reliability Standard PRC-012-2 applies to RCs, PC, and RAS-entities. As the
RC maintains the requisite “[w]ide-[a]rea” perspective to “prevent or mitigate emergency
operating situations in both next-day analysis and real-time operations,” 39 the RC is the
appropriate entity to review each new or functionally modified RAS in its respective area to
ensure area-wide reliability and to collect pertinent RAS data in a RAS database. This
perspective allows the RC to evaluate interactions among separate RAS and other protection and
control systems. Further, given the RC’s unique responsibility and the typical business
arrangement of an RC with entities within the RC area, the RC is the entity least likely to have
conflicts of interest, including business relationships, with RAS-entities, PCs, and other relevant
entities.
39
NERC Glossary (updated on June 24, 2016) at 81, available at
http://www.nerc.com/files/glossary_of_terms.pdf.
13
The PC is the functional entity responsible for assessing the “longer-term reliability”
within its area by coordinating, facilitating, integrating, and evaluating transmission facility and
service plans within its respective area. 40 As such, the PC is the appropriate functional entity to
maintain oversight of each RAS in its PC area so that it continues to function as planned. The
PC already fulfills responsibilities similar to the RAS modeling and studies required under
proposed PRC-012-2 and can thus perform the responsibilities of PRC-012-2 seamlessly.
Finally, in recognition of the need for a term to describe all entities that are responsible
for a RAS, NERC developed the term “RAS-entity” to describe the Transmission Owner(s),
Generator Owner(s), or Distribution Provider(s) that “owns all or part of a RAS.” 41 This broad
term captures each entity involved in RAS ownership. Outside of agreements among responsible
entities regarding compliance with applicable standards, the standard remains applicable to each
entity that owns all or part of a RAS. Taken together, the proposed Requirements obligate the
RC, PC, and RAS-entity to share resources and collaborate to the extent necessary to establish a
continent-wide RAS program.
B.
Requirement by Requirement Justification
Proposed Reliability Standard PRC-012-2 consists of nine Requirements that individually
contribute to its stated purpose. As reflected in Exhibit G, NERC’s Proposal satisfies the
Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The subsections below provide additional justification
and information regarding each Requirement or group of Requirements, as follows:
i)
40
41
three Requirements obligating the RC to engage in a RAS review process
(Requirements R1, R2, and R3);
See id at 69; see also Reliability Functional Model (Version 5) at 22.
Section 4 of Reliability Standard PRC-012-2 (see Exhibit B).
14
ii)
one Requirement mandating the PC to engage in a periodic review of each RAS
(Requirement R4);
iii)
one Requirement ensuring that the RAS-entity continuously reviews its RAS upon
operation or misoperation (Requirement R5);
iv)
two Requirements enacting a process for RAS-entities to address issues with each
RAS identified by the RC in its RAS review (Requirements R6 and R7);
v)
one Requirement obligating the RAS-entity to perform a periodic functional test for
each of its RAS (Requirement R8); and
vi)
one Requirement mandating the RC to establish a RAS database (Requirement R9).
i)
Requirements R1, R2, and R3
R1. Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS-entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R2. Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually agreed
upon schedule, perform a review of the RAS in accordance with Attachment 2, and
provide written feedback to each RAS-entity. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
R3. Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain approval
of the RAS from each reviewing Reliability Coordinator. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
Proposed Requirements R1, R2, and R3 establish an RC review process for each new or
functionally modified RAS that must be completed before a RAS-entity places a RAS into
service. The RAS review is the first step towards evaluating and coordinating RAS across the
RC area, including those in neighboring RC areas, to ensure that RAS do not introduce
“unintentional or unacceptable reliability risks” into the BES. As noted above, the RC is the
appropriate entity to perform the RAS review because the RC has a wide-area reliability
perspective and awareness of reliability issues in neighboring RC areas.
15
Under Requirement R1, a RAS-entity must provide the reviewing RC with the data
included in Attachment 1 to the standard before placing the “new or functionally modified” RAS
into service or retiring an existing RAS. Attachment 1 identifies a variety of targeted, pertinent
information regarding the RAS design, function, and operation that the RC needs to perform the
RAS review. As such, the reviewing RC would only review particularized information deemed
relevant for purposes of maintaining reliability. NERC designed Attachment 1 to eliminate any
ambiguity in the information that a RAS-entity must submit to the RC for review to make a
determination about whether the RAS may be approved.
Just as the RC must review new RAS to determine whether the new device would impact
operations once implemented, the RC must also review RAS that have been “functionally
modified” to ensure that any changes made to the RAS do not introduce new issues into the BES.
According to footnote 2 of Attachment 1 and footnote 4 of Attachment 2, a RAS is deemed
“functionally modified” if the RAS-entity experiences any of the following:
i)
changes to System conditions or Contingencies monitored by the RAS;
ii)
changes to the actions that the RAS is designed to initiate;
iii)
changes to RAS hardware beyond hardware replacement that matches the original
functionality of existing components;
iv)
changes to RAS logic beyond correcting existing errors; or
v)
addition or removal of redundancy levels. 42
When an entity submits a “functionally modified” RAS for review, the RC is only
required to review details of the proposed modifications; however, the submitting RAS-entity
must provide a summary of existing functionality in Attachment 1 to provide sufficient context
42
NERC provides additional information about what constitutes a functional modification in the Reliability
Standard PRC-12-2 Remedial Action Schemes Question & Answer Document, attached herein as Exhibit F.
16
for the RAS modifications to allow the RC to perform an abbreviated review of the RAS. After
the RAS-entity completes and delivers Attachment 1 to the reviewing RC, the RC must begin its
comprehensive review of the affected RAS pursuant to proposed Requirement R2.
Under Requirement R2, the RC is required to perform a RAS review in accordance with
Attachment 2 within four months of receiving a completed Attachment 1, or on an otherwise
agreed upon schedule. Attachment 2 is a detailed checklist of criteria that the RC must use to
identify design and implementation aspects of the RAS that are critical to an effective RAS
review framework. By requiring the RC to perform the RAS review according to Attachment 2
(Reliability Coordinator RAS Review Checklist) of proposed PRC-012-2, 43 Requirement R2
establishes a comprehensive, consistent review process. The RC, when performing the review,
may request assistance from other parties that have access to relevant information about the
RAS, such as the PC or regional technical groups; however, the RC is ultimately responsible for
compliance with Requirement R2. This delineation of responsibility, which holds the RC
responsible as an independent party, helps to mitigate any conflict of interest that may exist due
to business relationships among the RAS-entity, PC, Transmission Planner (“TP”), or other
entities that are likely to be involved in the planning or implementation of a RAS.
In observance of the time needed to complete each review, the RC must perform the
Attachment 2 review within four full calendar months, or on an otherwise negotiated basis. This
periodicity is consistent with industry practice and provides adequate time for a complete review,
and it includes additional flexibility for unique or unforeseen circumstances. Upon completion
of the review, the RC must provide the RAS-entity with the results of its RAS review identifying
43
Examples of issues that the RC may identify with each RAS include, but are not limited to, a lack of
dependability, security, or coordination. Notably, the Reliability Coordinator RAS Review Checklist warns that the
“RC review is not limited to the checklist items and the RC may request additional information on any aspect of the
RAS as well as any reliability issue related to the RAS.”
17
reliability issues that must be resolved before the RAS-entity can place the RAS into service.
The RAS-entity may place the RAS into service only when the reviewing RC’s feedback to each
RAS-entity indicates either that no reliability issues were identified during the review or that all
reliability issues identified by the RC have been resolved to the satisfaction of the reviewing RC,
as required under Requirement R3.
Requirement R3 requires the RAS-entity to resolve any reliability issues with the RAS
identified by the RC before the RAS-entity places the RAS into operation. While there is no
explicit timeframe for the RAS-entity and the RC to resolve the issues identified by the RC and
to approve the RAS, respectively, the RAS-entity and the RC would be motivated to do so on a
timely basis. The RAS-entity would not be permitted to place a RAS in service unless the RASentity has taken all remedial steps prescribed by the RC as a result of the RAS review. Because
the RAS-entity is the party requesting approval of a RAS to be placed into service and would
want approval as soon as possible, the RAS-entity is incentivized to address any RC concerns as
quickly as possible. Similarly, the RC, the functional entity with significant responsibility for
maintaining BES reliability in its area, is motivated to approve new or modified RAS that
improve BES reliability. As discussed above, because RAS play an important role in helping to
ensure reliable operations, an RC would thus act with expediency to approve a RAS that
improves reliability to continue fulfilling its responsibility. Accordingly, a specific period for
remediation of the identified issues and approval of each RAS is unnecessary.
ii)
Requirement R4
R4. Each Planning Coordinator, at least once every five full calendar years, shall:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for
which it was designed.
18
4.1.2. The RAS avoids adverse interactions with other RAS, and
protection and control systems.
4.1.3. For limited impact 44 RAS, the inadvertent operation of the RAS or
the failure of the RAS to operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations.
4.1.4. Except for limited impact RAS, the possible inadvertent operation
of the RAS, resulting from any single RAS component malfunction
satisfies all of the following:
4.1.4.1. The BES shall remain stable.
4.1.4.2. Cascading shall not occur.
4.1.4.3. Applicable Facility Ratings shall not be exceeded.
4.1.4.4. BES voltages shall be within post-Contingency voltage
limits and post-Contingency voltage deviation limits as established
by the Transmission Planner and the Planning Coordinator.
4.1.4.5. Transient voltage responses shall be within acceptable
limits as established by the Transmission Planner and the Planning
Coordinator.
4.1.5. Except for limited impact RAS, a single component failure in the
RAS, when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified
deficiencies to each reviewing Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning Coordinator.
The purpose of Requirement R4 is to ensure that there are periodic reviews of a RAS
after the RAS-entity places it in service to confirm that the RAS continues to function as planned
and does not adversely affect reliable operations or introduce any “unintentional or unacceptable
reliability risks” into the BES. 45 After the RC has reviewed and approved a RAS pursuant to
Requirements R1-R3, and the RAS-entity places it into service, the RAS-entity may experience
44
”A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.” See Reliability Standard PRC-012-2 (attached herein as Exhibit B).
45
The purpose of Requirement R4 is consistent with the purpose of proposed Reliability Standard PRC-0122, which is “[t]o ensure that Remedial Action Schemes (RAS) do not introduce unintentional or unacceptable
reliability risks to the Bulk Electric System (BES).”
19
changes in System topology or operating conditions that necessitate an additional evaluation of
affected RAS. As such, Requirement R4 creates an affirmative obligation on the PC to conduct
periodic evaluations of each in-service RAS.
As discussed above, because the PC is the entity that “coordinates and integrates
transmission Facilities and service plans, resource plans, and Protection Systems” with a wide
area planning perspective, the PC is the appropriate entity to conduct this continuous oversight of
each in-service RAS pursuant to Requirement R4. The PC is responsible for conducting the
evaluation of RAS in its area under Requirement R4. If the RAS crosses PC boundaries, each
affected PC is responsible under Requirement R4 for conducting either individual evaluations or
participating in a coordinated evaluation. 46
The PC must evaluate each RAS in its area every five years. As provided in the
Implementation Plan associated with proposed PRC-012-2, the PC must complete initial
performance of this requirement for each new and functionally modified RAS within five years
after the date of RC approval of the RAS. 47 For each existing RAS, the PC must complete initial
performance of this requirement within five years after the effective date of the proposed
standard. Five years is an appropriate periodicity for PC review of each RAS as it corresponds to
the five-year performance period required under Reliability Standards PRC-006, PRC-010, and
PRC-014. These standards require responsible entities to perform effectiveness evaluations on
remedial equipment similar to the evaluation required under Requirement R4 of proposed PRC012-2, so alignment with PRC-006, PRC-010, and PRC-014 would improve consistency and
46
See Reliability Standard PRC-012-2 at 34 (Technical Justification).
NERC notes that five (5) years is the maximum allowable interval in between evaluations under
Requirement R4, so even if a RAS is functionally modified during the initial five (5) year period, the responsible
entity must continue to fulfill the performance obligation within the initial five (5) year period. See Implementation
Plan for PRC-012-2 (Exhibit C) at 2.
47
20
would streamline various evaluation processes. 48 While this is the maximum allowable interval
between PC reviews, the PC may evaluate a RAS more frequently if necessary in response to a
new generator interconnection, transmission system changes, changes in load, etc. This periodic
RAS evaluation should lead the PC to provide one of the following determinations: 1)
affirmation that the existing RAS is effective; 2) identification of changes needed to the existing
RAS; or, 3) justification for RAS retirement.
Using a risk-based approach, the nature of the evaluation mandated by Requirement R4
depends on whether the relevant RC has designated the RAS as a “limited-impact RAS.”
Attachment 2 of PRC-012-2 provides that RCs may designate a RAS as “limited impact” if the
RC determines that the RAS is incapable of causing significant adverse BES reliability impacts.
As described in footnote 1 of Reliability Standard PRC-012-2, a “limited impact RAS” is a RAS
that “cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.”
The proposed standard imposes more detailed evaluation requirements on RAS that are
not designated as “limited impact,” consistent with the greater risks they present to BES
reliability. For non-limited impact RAS, the PC must perform an evaluation consistent with all
the subparts of Requirement R4 except Part 4.1.3. The evaluation requirements contained in
Parts 4.1.1, 4.1.2, 4.1.4, and 4.1.5, obligate the PC to confirm that:
o the RAS mitigates the System condition(s) or Contingency(ies) for which it was
designed;
48
Reliability Standard PRC-010-2 requires the PC and TP is required to perform an effectiveness evaluation
of its UVLS program once every five years. Reliability Standard PRC-006-2 requires the PC to conduct a UFLS
assessment every five years to ensure compliance with certain criteria. Reliability Standard PRC-014-1 (which the
Commission has not approved or remanded) requires the responsible entity to assess each RAS in its respective area.
21
o the RAS avoids adverse interactions with other RAS, and protection and control
systems;
o when inadvertent operation of the RAS occurs, the BES remains stable, cascading
does not occur, ratings are not exceeded, voltages are within limits, and voltage
responses are within limits; and
o a single component failure in the RAS does not prevent the BES from meeting
requirements in TPL-001-4 as required for the events and conditions for which the
RAS is designed.
For limited impact RAS, the PC must only conduct an evaluation consistent with Parts
4.1.1, 4.1.2, and 4.1.3 to confirm that: (1) the RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed; (2) the RAS avoids adverse interactions with other
RAS, and protection and control systems; and (3) the inadvertent operation of the RAS or the
failure of the RAS to operate does not cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The SDT determined that the additional elements of the evaluations for non-limited
impact RAS provided in Parts 4.1.4 and 4.1.5 should not be required for “limited impact” RAS
given that they present a lower risk to BPS reliability, as further discussed below.
The following discussion provides (i) additional technical justification for distinguishing
“limited impact” RAS from all other RAS, and (ii) an explanation of the relationship between
Requirement R4 of proposed PRC-012-2 and currently-effective Reliability Standard TPL-001-4.
a)
Limited Impact RAS
This section provides an explanation of: (1) the need for the “limited impact” RAS
designation; (2) the process by which the RC may designate a RAS as “limited impact; and (3)
the process by which the PC is obligated to periodically evaluate whether the “limited impact”
RAS should continue to be designated as limited impact.
22
Need for Limited Impact Designation: Each RAS is unique in geography, purpose,
design, and complexity. Depending on these characteristics and the problems that the RAS are
designed to mitigate, there may be significant differences amongst RAS as to their potential
impact on the reliability of the BES. A RAS would have a small impact if the RAS-entity
designs or implements the RAS such that it cannot, by inadvertent operation or failure to operate,
cause or contribute to major reliability issues. While these smaller impact RAS are important for
reliability, they are technically incapable of causing critical issues that could impact operations
across a large area.
An example of a limited impact RAS is a scheme applied on an interconnection between
two utilities, with one side of the tie consisting of a 230 kV line in parallel with a long 115 kV
line that does not provide significant support to the intertie. The other side of the intertie is a 345
kV line. Depending on pre-contingency magnitude and direction of flow, the scheme is armed to
do one of the following upon loss of the 230 kV line: (i) nothing; 49 (ii) switch a shunt reactor; or
(iii) open the 345 kV tie. This RAS mitigates voltage deviation greater than 5%, but it is not
designed to address voltage level, overload, Cascading, or other serious operational issues that
would exclude the RAS from being “limited impact.”
In contrast, an example of a non-limited impact RAS is one that separates the WECC
system into two planned islands following loss of three parallel 500 kV lines connecting Oregon
and California. This islanding scheme is armed depending on pre-event flows. In addition to
islanding and other actions, the RAS may drop more than 2000 MW of generation, a similar
amount of load shedding, and switch shunt reactive devices at multiple locations across most of
the WECC system. The non-limited impact RAS mitigates problems including Cascading,
49
There are some system conditions for which no action is required.
23
unplanned islanding, angular and voltage instability and possible collapse of major parts of the
System, each result substantially more critical than those mitigated by the limited impact RAS
described above.
Recognizing the significant differences amongst RAS and the need to focus industry
resources on those RAS that present greater risk to BES reliability, proposed Reliability Standard
PRC-012-2 (1) establishes a process whereby the RC may designate a RAS as “limited impact”
based on its characteristics, and (2) subjects limited impact RAS to a different set of
requirements than RAS that are not limited impact to account for the varying levels of risks
presented. The purpose of the designation is thus to maintain the risk-based nature of NERC
Reliability Standards by requiring applicable entities to review RAS in a manner that is
commensurate with the potential impact of the RAS on reliability.
Process for RC Designation of Limited Impact RAS: As noted above, under
Requirement R1, prior to placing a RAS into service, the RAS-entity must submit the
information contained in Attachment 1 to the RC for its review. In completing Attachment 1, the
RAS-entity must identify whether the RAS is limited impact and provide the reviewing RC with
technical justification establishing that the RAS is “limited impact.” Pursuant to Requirement
R2, the reviewing RC must review the RAS based on criteria in Attachment 2, which requires the
RC to consider the studies and information provided to the RC in Attachment 1 and determine
whether the RAS identified by the RAS-entity should be designated as a “limited impact” RAS.
The RC would designate the RAS as a limited impact RAS if it determines, based on its
review under Requirement R2, that the RAS “cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular instability,
24
voltage instability, voltage collapse, or unacceptably damped oscillations.” 50 When the RC
agrees that the RAS-entity has addressed each of the reliability issues identified by the RC, the
RC would approve the RAS, and if applicable, would designate it as “limited impact.” The
RAS-entity may place the RAS into service only after the RC is satisfied that all reliability issues
have been addressed.
Diversity among the different types, functions, and placements of RAS make it difficult
to establish a bright line rule for correctly and consistently identifying (existing and future) RAS
that are “limited impact” and RAS that are not “limited impact.” As such, proposed Reliability
Standard PRC-012-2 requires the RC to make this determination on a case-by-case basis based
on its review of the RAS. The RC is already required to approve a RAS based on various criteria
under Requirement R2, and the RC has the benefit of having all technical criteria included in
Attachment 1 for each RAS. Further, the RC is the appropriate entity to designate a RAS as
“limited impact” as it has the wide-area view and understanding of the BES to determine
whether a RAS “cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse,
or unacceptably damped oscillations.”
Prior to development of proposed PRC-012-2, two NERC Regions, the Northeast Power
Coordinating Council (“NPCC”) and the Western Electric Coordinating Council (“WECC”),
used individual RAS classification regimes to identify RAS that would meet similar criteria
described as “limited impact” in proposed PRC-012-2. Specifically, the standard drafting team
identified the Local Area Protection Scheme (“LAPS”) classification in WECC and the Type III
50
As the term “BES” in the explanation of “Limited Impact” modifies each of the conditions referenced
therein, “Limited Impact” RAS may not contribute to BES Cascading, BES uncontrolled separation, BES angular
instability, BES voltage instability, BES voltage collapse, or unacceptably dampened BES oscillations.
25
classification in NPCC as consistent with the “limited impact” designation. A RAS that was
implemented prior to the effective date of PRC-012-2 that has been through the regional review
processes of WECC or NPCC, and that is classified as either a LAPS by WECC or a Type III by
NPCC, would be considered a “limited impact” RAS for purposes of PRC-012-2 initially.
Accordingly, if WECC or NPCC has designated a RAS as “limited impact,” the RC does not
need to designate the RAS as “limited impact” through an initial review because the RAS is
already in service and was subject to the relevant regional review process. Notably, any LAPS
or Type III RAS is still subject to the periodic PC evaluation to confirm that the RAS still meets
the “limited impact” qualifications under Part 4.1.3. As provided in the Implementation Plan, the
PC must conduct an evaluation within 5 years of the effective date of the proposed Reliability
Standard. If PC finds that a LAPS or Type III RAS is not a limited impact RAS, the LAPS or
Type III RAS will no longer retain that designation. NERC has provided a series of examples of
currently active LAPS and Type III schemes in Exhibit A.
PC Evaluation of Limited Impact RAS: While the RC is responsible for performing the
initial designation of limited impact RAS, Requirement R4 of proposed PRC-012-2 requires the
PC to review the limited impact RAS to confirm its continued status as “limited impact” as part
of its periodic evaluation. Specifically, Requirement R4, Part 4.1.3 explicitly requires the PC to
evaluate all “limited impact” RAS to verify that the RAS does not, “by inadvertent operation or
failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations.” The PC
may use its discretion as to the method used to evaluate each limited impact RAS.
The PC is the appropriate entity to verify that a RAS continues to be “limited impact”
because the PC maintains a wide-area planning perspective to determine whether the designation
26
still applies, and the PC can provide the results of the evaluation to each impacted TP, PC, RC,
and RAS-entity. If the PC determines that the RAS maintains this qualification, the limited
impact designation remains applicable; however, if the PC determines that this is no longer
applicable to the RAS, then the RC may choose to withdraw the limited impact designation at
which point the RAS would become subject to the single component failure and malfunction
tests under R4.1.4 and R4.1.5. All limited impact RAS, whether designated by the RC or under a
preexisting regional process described above, would be periodically reviewed under the
verification provision in Requirement R4.
RAS designated as “limited impact” RAS are not subject to the single component
malfunction and failure evaluations in Parts 4.1.4 and 4.1.5 of proposed Reliability Standard
PRC-012-2, respectively. Under Requirement R4, Part 4.1.4, the PC must review individual
RAS components to determine whether an inadvertent operation of a RAS would have a BESwide impact (i.e., Cascading, failure to meet Applicable Facility Ratings, etc.). Similarly,
Requirement R4, Part 4.1.5 requires the PC to review single component failures in RAS to
confirm that the failure does not prevent the BES from meeting the performance requirements of
TPL-001-4. RAS that are “limited impact” cannot, by inadvertent operation or failure to operate,
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations.” In its initial review of the
RAS, the RC designated the RAS as limited impact because it met these qualifications. As
limited impact RAS cannot, by definition, fail the evaluations in Requirement R4, Parts 4.1.4 and
4.1.5, the PC does not need to perform the inadvertent operation analysis or single component
failure analysis under these parts. Accordingly, requiring a limited impact RAS to meet these
tests would provide little to no benefit to BES reliability.
27
b)
Relationship to Reliability Standard TPL-001-4
Requirement R4 of proposed PRC-012-2 does not supersede or modify PC
responsibilities under Reliability Standard TPL-001-4 but works with Reliability Standard TPL001-4 to require the inadvertent operation of certain RAS to meet, at a minimum, performance
requirements common to all planning events listed in TPL-001-4.
Reliability Standard TPL-001-4 sets forth Transmission system planning performance
requirements for various System conditions and probable Contingencies. Table 1 of Reliability
Standard TPL-001-4 explains the specific performance requirements that a RAS must meet
according to the Contingency or System condition. Similarly, under Parts 4.1.1, 4.1.2, 4.1.3,
4.1.4, and 4.1.5 of Requirement R4 of proposed PRC-012-2, the PC must complete an evaluation
of each RAS to ensure that it operates appropriately and that it meets certain performance
criteria. While the requirements under TPL-001-4 and PRC-012-2 are similar, proposed PRC012-2 introduces the possibility of RAS failure to operate and RAS inadvertent operation,
matters on which TPL-001-4 is silent.
Specifically, Part 4.1.4 of Requirement R4 requires the PC to verify that the possible
inadvertent operation of the RAS, except for a limited impact RAS, meets the minimum System
performance requirements in Table 1 of Reliability Standard TPL-001-4. Instead of referring to
TPL-001-4, however, the Requirement lists the System performance requirements that a potential
inadvertent operation must satisfy, which account for the performance requirements common to
all planning events P0-P7 in TPL-001-4. 51 Similarly, Part 4.1.5 of proposed PRC-012-2
mandates that the PC evaluate whether the RAS, except for limited impact RAS, upon the
occurrence of a single component failure, continues to meet “the same performance requirements
51
Requirement R4, Parts 4.1.4.1 and 4.1.4.5, require the PC to confirm that the BES remains stable and that
voltage is within acceptable limits, respectively.
28
(defined in Reliability Standard TPL-001-4 or its successor) as those required for the events and
conditions for which the RAS is designed.” Even though Part 4.1.5 exempts limited impact
RAS, the standard does not exempt limited impact RAS from meeting each of the performance
requirements in TPL-001-4. 52
Thus, while limited impact RAS are exempt from RC evaluation under Parts 4.1.4 and
4.1.5, these RAS are not exempt from performance requirements in TPL-001-4. The
performance requirements under TPL-001-4 and PRC-012-2 are thus designed to support one
another and are not mutually exclusive.
iii)
Requirement R5
R5. Each RAS-entity, within 120 full calendar days of a RAS operation or a failure of its
RAS to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine
whether:
5.1.1. The System events and/or conditions appropriately triggered the
RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES
response.
5.2. Provide the results of RAS operational performance analysis that identified
any deficiencies to its reviewing Reliability Coordinator(s).
Pursuant to Requirement R5, RAS-entities must complete a performance analysis of each
of its RAS upon the operation or failure to operate of that RAS. This Requirement is necessary
for BES integrity and reliability as it verifies that each RAS operation (or misoperation) is
consistent with its intended functionality and design. More specifically, the RC and PC reviews
52
As an example of the coordinated nature of TPL-001-4 and PRC-012-2, the RC may use the analysis
completed under the TPL Requirements in its evaluation of whether a RAS qualifies as “limited impact” under
Requirements R1, R2, and R3.
29
performed under Requirements R2 and R4, respectively, RAS are designed to verify the
technical integrity of the RAS, not to analyze the operation or misoperation of RAS. An analysis
of the actual operation of the RAS according to its design is critical to maintaining the reliability
and integrity of the BES. As such, in addition to the reviews required under Requirements R2
and R4, Requirement R5 creates an affirmative obligation for RAS-entities to analyze a RAS
after each operation or misoperation. A RAS-entity would be in the best position to review a
RAS directly after an event to determine whether the RAS operates correctly and as intended.
Under Requirement R5, each RAS-entity must complete an operational performance
analysis after each operation or failure of a RAS to operate to verify that the RAS operated as
designed and to identify any deficiencies that occurred during operation, including any adverse
effect on the BES. The RAS-entity must analyze RAS performance and provide the details of
any deficiencies to the relevant reviewing RC within 120 days of a RAS operation or a failure of
the RAS to operate when expected, or on another schedule agreed to by the RC. The 120-day
period is consistent with the amount of time required for responsible entities to complete the
Protection System Misoperation investigation under Requirements R1, R2, and R3 of Reliability
Standard PRC-004-5.
It is important for proposed PRC-012-2 and Commission approved PRC-004-5 to operate
contemporaneously, as both standards require the entity responsible for the RAS to perform an
analysis when a RAS misoperates. Specifically, Requirements R1, R2, and R3 of Reliability
Standard PRC-004-5 focuses on identification, communication and mitigating reoccurrence of a
misoperation of a RAS. Requirement R5 of proposed PRC-012-2 focuses on analysis and
communication of operation or misoperation of a RAS. Aligning the timeframes for both
standards and providing the flexibility for the RAS-entity and RC to agree upon an alternative
30
schedule ensures that, after a RAS misoperation, responsible entities can perform the required
analyses on a consistent schedule. Finally, consistent with NERC’s Proposal, which requires the
RC to maintain continued oversight of each in-service RAS (i.e., the requirements for the RC to
review and approve each RAS and for the RC to maintain a database of each RAS in its area)
Part 5.2 of Requirement R5 requires the RAS-entity to provide the results of all RAS operational
performance analyses that identify deficiencies to its reviewing RC(s).
As the TP may have access to information needed to perform the analysis under
Requirement R5, 53 RAS-entities may need to collaborate with their associated TP to verify that
the RAS was triggered correctly, responded as designed, and affected the BES as intended.
Regardless, the RAS-entity continues to be the responsible entity for purposes of compliance
with Requirement R5. RAS-entities with a common RAS (i.e., more than one RAS-entity is
responsible for a single RAS) may collaborate to conduct and submit a single, coordinated
operational performance analysis.
iv)
Requirements R6 and R7
R6. Each RAS-entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Longterm Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency pursuant to Requirement R5,
Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long-term
Planning]
53
The TP is responsible for developing a long-term reliability plan for the interconnection BES, and
information in the reliability plan may be useful to determine whether, according to this plan, the RAS was triggered
correctly, responded as designed, and affected the BES as intended. As such, the TP may have useful information
for conducting the analysis.
31
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables
change and when the CAP is completed.
The reliability objective of Requirements R6 and R7 is to require a RAS-entity to take all
necessary steps to address deficiencies associated with its RAS after becoming aware of the
deficiency. Under these Requirements, RAS-entities are required to create a CAP to respond to
deficiencies with the affected RAS, implement the CAP, update the CAP, and inform the RC of
the status of updates and implementation of the CAP.
A RAS-entity may discover deficiencies with its RAS in one of three ways. First, the PC
may notify the RAS-entity of an issue with a RAS as a result of its evaluation under Requirement
R4. Second, the RAS-entity may discover an issue with its RAS based on its performance
analysis after the operation of the RAS or failure of the RAS to operate. Third, the RAS-entity
may discover a deficiency with its RAS during its periodic functional test under Requirement
R8.
Pursuant to Requirement R6, the RAS-entity must develop a CAP to address any
identified deficiency to mitigate potential reliability risks associated with this deficiency. A CAP
is defined in the NERC Glossary as “[a] list of actions and an associated timetable for
implementation to remedy a specific problem.” Accordingly, the RAS-entity must design the
CAP to facilitate the corrective measures in the plan by describing all actions necessary to
address the deficiency with the RAS and by providing an associated timetable to complete these
actions. NERC anticipates that the RAS-entity may design the CAP with information obtained
from other parties such as the TP or PC, but the RAS-entity is the entity responsible for
compliance with Requirement R6. Depending on the complexity of the identified
32
deficiency(ies), the RAS-entity may need to perform studies or other engineering or consulting
work to adequately develop the CAP.
The RAS-entity must develop and submit the CAP to the relevant RC within six months
of one of the following: (i) the PC notifies the RAS-entity of the deficiency under Requirement
R4, (ii) the RAS-entity notifies the RC of a deficiency under Requirement R5, or (iii) the RASentity identifies a deficiency under Requirement R8. NERC designed Requirement R6 as a
careful balance between the need for RAS-entity collaboration with other RAS-entities or the
relevant TP or PC with the need to address the deficiencies in a reasonable, effective time.
Based on this calculation, Requirement R6 specifies a maximum period of six full calendar
months for RAS-entity collaboration on the CAP development. Ideally, when there is more than
one RAS-entity for a RAS, the RAS-entities would collaborate to develop and submit a single,
coordinated CAP.
Pursuant to Requirement R7, each RAS-entity must implement the CAP developed
according to Requirement R6 (or, more plainly stated, take the actions described in the CAP
within the associated timeframe) to address the identified deficiencies. To satisfy its obligations
pursuant to Requirements R6 and R7, the RAS entity must develop a CAP designed to mitigate
any deficiencies with the RAS in a timely manner. If the RAS-entity makes any change to the
actions or schedule in its CAP, the RAS-entity must update the CAP and submit the revised CAP
to the RC. In addition, the RAS-entity must notify the RC when the actions under the CAP have
been complete and the deficiencies have been addressed. Finally, in the event that the RASentity designs a CAP that requires the RAS-entity to make a functional modification to the RAS
to address the deficiency, the RAS-entity must resubmit the RAS to the RC for review by
submitting information identified in Attachment 1 according to proposed Requirement R1. This
33
is consistent with a RAS-entity’s continued obligation under Requirement R1 to obtain RC
approval for each “new or functionally modified” RAS.
v)
Requirement R8
R8. Each RAS-entity shall participate in performing a functional test of each of its RAS
to verify the overall RAS performance and the proper operation of non-Protection System
components: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
•
•
At least once every six full calendar years for all RAS not designated as limited
impact, or
At least once every twelve full calendar years for all RAS designated as limited
impact.
In addition to the operational analysis that each RAS-entity must complete after operation
or misoperation of a RAS under Requirement R5 of proposed PRC-012-2, the RAS-entity must
perform a functional test of its RAS on a periodic basis pursuant to Requirement R8. This
functional test serves as additional confirmation that the RAS and the non-Protection System
components of the RAS operate as designed.
Responsible entities must test Protection System components that are part of a RAS
pursuant to Reliability Standard PRC-005; however, RAS-entities are not required to test the
non-protection RAS device (e.g., controller) under any other currently effective Reliability
Standard. As each RAS placed in service by a RAS-entity is unique in its operation, location,
and design, and role in BES reliability, periodic functional testing of the actual RAS is necessary
to maintain reliability across the BES. NERC designed Requirement R8 to require each RASentity, as the party with knowledge of the design, installation, and functionality of the RAS, to
perform periodic functional testing of each of its RAS to ensure that it continues to operate as
designed. A successful functional test that meets the criteria in Requirement R8 to “verify the
overall RAS performance and the proper operation of non-Protection System components”
34
would gauge the effectiveness of the device and ensure that the RAS continues to function
properly and as designed.
In performing the test, the RAS-entity may test the RAS using an end-to-end testing
method or a segmented approach to perform a functional test on all RAS non-protection system
components or other components of the RAS not already covered in PRC-005-6. If the RASentity employs a segmented approach to testing, the RAS-entity must test each segment of a RAS
and may test overlapping segments individually. This individual segment testing, as opposed to
testing all segments at the same time, eliminates the need for complex maintenance schedules
and outages that may be necessary otherwise. A successful test of one segment only resets the
test interval clock for that segment.
Further, when a RAS operates and the RAS-entity performs the analysis under
Requirement R5, Part 5.1, the RAS-entity may use the evidence for compliance with Part 5.1 as
evidence for compliance with Requirement R8 (i.e., the RAS would be deemed “tested” for
purposes of Requirement R8). If one or more segments does not operate, however, the segments
that did not operate must be tested within the maximum interval beginning on the date of the
previous successful test of the segment(s) that did not operate.
The RAS-entity must perform a functional test for each RAS that is not designed as
“limited impact” 54 at least once “every six full calendar years,” and for each limited impact RAS
at least once “every twelve full calendar years.” NERC developed this timeline to ensure that
entities have adequate time and resources to acquire and develop the testing framework and to
address the potential reliability impacts to the BES created by undiscovered or latent issues that
54
NERC characterizes a “limited impact RAS” in footnote 1 of proposed PRC-012-2 as a “RAS designated as
limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES Cascading,
uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.”
35
may have an adverse impact on the operation of a RAS. As explained in the Implementation
Plan for PRC-012-2 (attached herein as Exhibit C), the initial performance obligation for entities
responsible for compliance with Requirement R8 must be completed within either six (6) or
twelve (12) years after the effective date for PRC-012-2, depending on the type of RAS being
tested. This six- and twelve-year timeframe is also consistent with the timeframes for
component maintenance requirements related to protection systems, automatic reclosing, and
sudden pressure relaying in Table 1-1 of Reliability Standard PRC-005-6. 55
vi)
Requirement R9
R9. Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
Under Requirement R9, each RC is required to create a comprehensive RAS database
including all relevant information for each RAS in its RC area and to update this database every
twelve months. The RAS database would serve as a tool for the RC to organize necessary RAS
data for the needs within its own area and to provide high-level RAS data to relevant entities to
identify vulnerabilities and to aid in reliability-related needs across the system.
Requirement R9 obligates the RC to collect information about each RAS in the relevant
RC Area identified in Attachment 3. NERC designed Attachment 3 to require the RC to update
the minimum information required for the RAS database, including a summary of conditions that
trigger a RAS, the corrective actions performed by a RAS, and System issues that are mitigated
through corrective action taken by the RAS. The collection of the necessary database
55
Requirement R1 of PRC-005-6 requires each Transmission Owner, Generator Owner, and Distribution
Provider to establish a Protection System Maintenance Program (PSMP) for its Protection Systems, Automatic
Reclosing, and Sudden Pressure Relaying based on a schedule consistent with the maintenance intervals specified in
Table 1-1 of PRC-005-6. Table 1-1 defines the intervals for maintenance and the types of maintenance activities
which must be performed on components with particular attributes.
36
information is not onerous on the RC, as the data required in Attachment 3 is similar in scope
and substance to the information provided to the RC in Attachment 1 pursuant to Requirement
R1.
The RC would use the RAS data it collects under Requirement R9 to fulfill its reliabilityrelated responsibilities and to provide other entities with information about each existing RAS
that may impact the other entity’s operational and planning activities. While the RC may collect
more information than just the data nodes requested in Attachment 3, the RC must, at a
minimum, update the information in Attachment 3. Again, given its wide-area view and its
responsibility to receive relevant information about each RAS before the RAS-entity places the
RAS into service, the RC is the appropriate entity to compile RAS-related information specific to
each RAS for reliability planning and system analysis across the system.
Operational modeling information is regularly used in the development of NERC
powerflow base cases and reliability assessments, and it is provided yearly as required under
Reliability Standard MOD-032-1. Thus, consistent with established industry practice,
Requirement R9 obligates RCs to update its RAS database with all the information required in
Attachment 3 at least once every twelve months to ensure consistency and accuracy of pertinent
data. This timeframe provides sufficient time for RAS-entities to provide, and for RCs to collect,
all RAS information identified in Attachment 3.
Finally, RCs that do not have an established RAS database upon the effective date of
proposed PRC-012-2 would not be able to update information that has not yet been collected and
are thus not obligated to “update” the RAS database with the information included in Attachment
3. As described in the Implementation Plan and in Section IV.C of this Petition, RCs that have
not created a RAS database for collection of pertinent RAS information upon the effective date
37
of proposed Reliability Standard PRC-012-2 are required to create a RAS database by the
effective date of PRC-012-2. Upon this initial compliance obligation, the RC would be required
to continue to perform the obligation under Requirement R9 every twelve (12) calendar months.
C.
Enforceability of Proposed Reliability Standard PRC-012-2
Proposed Reliability Standard PRC-012-2 includes nine Measures to individually support
each Requirement, to clarify necessary evidence or actions for compliance, and to help ensure
that the Requirements are enforced in a clear, consistent, non-preferential manner, and without
prejudice to any party. Each of the nine associated Measures are provided below.
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with the
RAS-entity in accordance with Requirement R2.
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues were
identified during the review or that all identified reliability issues were resolved in
accordance with Requirement R3.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS-entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
M5. Acceptable evidence may include, but is not limited to, dated documentation
detailing the results of the RAS operational performance analysis and dated
communications with participating RAS-entities and the reviewing Reliability
Coordinator(s) in accordance with Requirement R5.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS-entity in
accordance with Requirement R6.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
38
maintenance records, and communication with the reviewing Reliability Coordinator(s)
that documents the implementation, updating, or completion of a CAP in accordance with
Requirement R7.
M8. Acceptable evidence may include, but is not limited to, dated documentation
detailing the RAS operational performance analysis for a correct RAS segment or an endto-end operation (Measure M5 documentation), or dated documentation demonstrating
that a functional test of each RAS segment or an end-to-end test was performed in
accordance with Requirement R8.
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
Proposed Reliability Standard PRC-012-2 also include VRFs and VSLs for each
Requirement. The VSLs and VRFs are part of several elements used to determine an appropriate
sanction when the associated Requirement is violated and each comports with the NERC and
Commission guidelines relate to their assignment. The VSLs provide guidance on the way that
NERC would enforce the Requirements of the proposed Reliability Standards. The VRFs assess
the impact to reliability of violating a specific Requirement and represent one of several elements
used to determine an appropriate sanction when the associated Requirement is violated.
As further explained in Exhibit D of this Petition, seven of the Requirements in proposed
Reliability Standard PRC-012-2 have been assigned a “Medium” VRF, while Requirement R8
has been assigned a VRF of “High” and Requirement R9 a VRF of “Lower.” Reflective of the
nature of the required action, each of the Requirements have been assigned Time Horizons of
either “Operational Planning” or “Long-term Planning.” As described in Exhibit D, the VRFs
and VSLs for the proposed Reliability Standard comport with NERC and Commission
guidelines. 56
56
See, e.g., N. Am. Elec. Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120
FERC ¶ 61,145 (2007).
39
D.
Proposed Retirements and Withdrawals
In an ongoing effort to consolidate and to remove unnecessary or redundant
Requirements or Reliability Standards from its currently effective suite of standards, NERC
proposes to retire two currently effective Reliability Standards and withdraw three Reliability
Standards that are currently pending with the Commission. As described in the Mapping
Document for PRC-012-2, attached herein as Exhibit E, proposed PRC-012-2 effectively
clarifies and streamlines a variety of existing Requirements applicable to Remedial Action
Schemes (formerly known as a “Special Protection System[s]”). As a result of this
consolidation, NERC proposes to retire currently effective Reliability Standards PRC-015-1 and
PRC-016-1 and withdraw pending “fill-in-the-blank” Reliability Standards PRC-012-1, PRC013-1, and PRC-014-1. 57
i)
Reliability Standard PRC-012-1
In Order No. 693, the Commission did not approve, deny, or remand Reliability Standard
PRC-012-1, as the Commission deemed this standard a “fill-in-the-blank” standard. Reliability
Standard PRC-012-1, which is the basis for NERC’s development of proposed Reliability
Standard PRC-012-2, required Regional Entities to create a RAS review process and establish
RAS design criteria. As explained in the Mapping Document (Exhibit E), all of the
Requirements in PRC-012-1 except R2 are now covered in Requirements R1, R2, R3, R4, R5,
R6, and R8 of PRC-012-2, as these proposed Requirements obligate the RC, PC, and RAS-entity
to create a RAS review process and require the RAS-entity to design corrective measures to
correct deficiencies with its respective RAS. Requirement R2 of PRC-012-1 obligated the
57
See Paragraph 81 Criteria at Exhibit A (proposing to retire standards as “Administrative” if the “Reliability
Standard requirement requires responsible entities to perform a function that is administrative in nature, does not
support reliability and is needlessly burdensome.”); see also Order No. 788.
40
Regional Reliability Organization to provide its RAS review procedures to other Regional
Reliability Organizations and to NERC. In Order No. 693, the Commission did not approve or
remand this standard because the standard assigned responsibilities to Regional Reliability
Organizations and was “fill-in-the-blank” because it did not properly assign a defined
responsibility to a responsible entity. 58 Accordingly, Requirement R2 is administrative in nature
and does not contribute to reliability, so NERC did not include the requirement in proposed
Reliability Standard PRC-012-2. 59
Notably, Requirements R1.3 and R1.4 of PRC-012-1 require responsible entities to
ensure that failure of a RAS to operate “does not prevent the interconnected transmission system
from meeting…TPL-001-0, TPL-002-2, and TPL-003-0” and that an inadvertent operation of the
RAS shall “[m]eet the same performance requirement (TPL-001-0, TPL-002-0, and TPL-003-0)
as that required of the contingency for which it was designed, and not exceed TPL-003-0.” As
NERC explained in the Mapping Document (Exhibit E), the performance obligation in these
Requirements would be required under Requirements R1, R2, and R4 of proposed PRC-12-2.
As explained in Section IV.B(ii)(b) of this petition, while the proposed requirements do not
58
NERC developed proposed Reliability Standard PRC-012-2 in consideration of the fact that the
Commission neither approved or denied PRC-012-1 and deemed it a “fill-in-the-blank” Reliability Standard. The
revised, proposed standard removes the obligation on “Regional Reliability Organizations,” and instead places the
responsibility on appropriate NERC functional entities.
59
See Paragraph 81 Criteria at Exhibit A. The proposed Reliability Standard does not include a requirement
similar to Requirement R2 of PRC-012-1, as this requirement is “administrative” in nature based on the
Commission-approved Paragraph 81 Criteria B1. Pursuant to NERC’s Paragraph 81 Criteria, a requirement may be
retired if it “requires responsible entities (“entities”) to conduct an activity or task that does little, if anything, to
benefit or protect the reliable operation of the BES,” and it meets another one of the criteria described in Criteria B
of that document. One of those criteria, Criteria B1 (Administrative), states that a Reliability Standard requirement
may be retired if it “requires responsible entities to perform a function that is administrative in nature, does not
support reliability and is needlessly burdensome.”59 Criteria B1 also states that it is “designed to identify
requirements that can be retired or modified with little effect on reliability and whose retirement or modification will
result in an increase in the efficiency of the ERO compliance program…Strictly administrative functions do not
inherently negatively impact reliability directly and, where possible, should be eliminated or modified for purposes
of efficiency and to allow the ERO and entities to appropriately allocate resources.”
41
explicitly state that entities must continue to comply with the TPL requirements, responsible
entities must continue to comply with these Reliability Standards. Based on the foregoing,
NERC proposes to withdraw PRC-012-1 in its entirety.
ii)
Reliability Standard PRC-013-1
Similar to Reliability Standard PRC-012-1, the Commission declared that Reliability
Standard PRC-13-1 is a “fill-in-the-blank” standard and neither approved, denied, or remanded
the standard in Order No. 693. 60 Still, NERC considers the purpose of PRC-013-1, to require
responsible entities to maintain a RAS database with pertinent technical information for each
RAS, vital to an effective RAS review and maintenance standard. Accordingly, in developing
proposed Reliability Standard PRC-012-2, NERC established Requirement R9 to require RCs to
maintain a RAS database with specific design information. NERC designed Attachment 3 to
support Requirement R9 to ensure that the RAS database includes all relevant technical
information about each RAS in its database. The RC must maintain information about each RAS
as prescribed in Attachment 3 when creating a RAS database under Requirement R9, as
Attachment 3 addresses all information deemed relevant for each RAS in its RAS database.
Finally, similar to its treatment of Requirement R2 of Reliability Standard PRC-012-1, NERC
declines to include Requirement R2 of PRC-013-1 in proposed PRC-012-2, as it assigns
responsibility to a Regional Reliability Organization, establishes a “fill-in-the-blank” standard,
and is thus unnecessary. Based on the foregoing, NERC proposes to withdraw PRC-013-1 in its
entirety.
60
NERC developed proposed Reliability Standard PRC-012-2 in consideration of the fact that the
Commission neither approved or denied PRC-013-1 and deemed it a “fill-in-the-blank” Reliability Standard. The
revised, proposed standard removes the obligation on “Regional Reliability Organizations,” and instead places the
responsibility on appropriate NERC functional entities.
42
iii)
Reliability Standard PRC-014-1
In Order No. 693, the Commission neither approved, denied, or remanded Reliability
Standard PRC-14-1 and declared that it was a “fill-in-the-blank” standard. 61 However, NERC
believes that the performance obligation in PRC-014-1, which required responsible entities to
oversee each RAS installed in the respective Regions every five years to ensure that the RAS
meets certain criteria and to take correction actions to remediate any RAS that did not meet those
criteria, is necessary for an effective RAS program. NERC developed Requirement R4 as a
vestige of Reliability Standard PRC-14-1 by requiring the PC to provide oversight of each RAS
within the PC area. NERC also developed Requirement R6 based on PRC-014-1 to mandate
that each RAS-entity design a CAP to address issues identified in its RAS review. As the
obligations under Reliability Standard PRC-014-1 are now covered in Requirements R4 and R6
of proposed PRC-012-2, NERC proposes to withdraw Reliability Standard PRC-014-1.
iv)
Reliability Standards PRC-015-1 and PRC-016-1
As the relevant performance requirements in currently effective Reliability Standards
PRC-015-1 and PRC-016-1 are subsumed in proposed Reliability Standard PRC-012-2, NERC
proposes to retire PRC-015-1 and PRC-016-1.
The purpose of currently effective Reliability Standard PRC-015-1 is “[t]o ensure that all
Remedial Action Schemes (RAS) are properly designed, meet performance requirements, and
are coordinated with other protection systems. To ensure that maintenance and testing programs
are developed and misoperations are analyzed and corrected.” The performance obligations of
PRC-015-1 require responsible entities to collect data regarding each RAS, review each new or
61
NERC developed proposed Reliability Standard PRC-012-2 in consideration of the fact that the
Commission neither approved or denied PRC-014-1 and deemed it a “fill-in-the-blank” Reliability Standard. The
revised standard removes the obligation on “Regional Reliability Organizations,” and instead places the
responsibility on appropriate NERC functional entities.
43
functionally modified RAS, and to provide the RAS data to NERC and to Regional Reliability
Organizations as necessary. Each of the requirements in PRC-015-1 are vital to ensuring that
responsible entities document critical information about each RAS and review each new or
functionally modified RAS before placing the RAS into service. Accordingly, NERC has
integrated these requirements into Requirements R1, R2, and R3 of proposed Reliability
Standard PRC-012-2.
As explained above, these Requirements ensure that (i) each RAS-entity provide specific
and detailed information to the relevant RC for review, (ii) each relevant RC review the
sufficiency of the RAS design and implementation and provide feedback to the respective RASentity, and (iii) each RAS-entity resolves all issues identified by the RC in its RAS review. In
Order No. 693, the Commission directed NERC to remove all references to the Regional
Reliability Organization as a responsible entity. 62 Also, under proposed Reliability Standard
PRC-012-2, the RC reviews each RAS and collects information about each RAS in a RAS
database under the proposed Reliability Standard. Requirement R3 of PRC-015-1, which
requires responsible entities to provide information about each RAS directly to the Regional
Reliability Organization and to NERC, is unnecessary and duplicative and is not included in
proposed PRC-012-2. 63
62
Order No. 693 at P 157.
See Paragraph 81 Criteria at Exhibit A. The proposed Reliability Standard does not include a requirement
similar to Requirement R3 of PRC-015-1, as this requirement is “administrative” in nature based on the
Commission-approved Paragraph 81 Criteria B1. Pursuant to NERC’s Paragraph 81 Criteria, a requirement may be
retired if it “requires responsible entities (“entities”) to conduct an activity or task that does little, if anything, to
benefit or protect the reliable operation of the BES,” and it meets another one of the criteria described in Criteria B
of that document. One of those criteria, Criteria B1 (Administrative), states that a Reliability Standard requirement
may be retired if it “requires responsible entities to perform a function that is administrative in nature, does not
support reliability and is needlessly burdensome.”63 Criteria B1 also states that it is “designed to identify
requirements that can be retired or modified with little effect on reliability and whose retirement or modification will
result in an increase in the efficiency of the ERO compliance program…Strictly administrative functions do not
inherently negatively impact reliability directly and, where possible, should be eliminated or modified for purposes
of efficiency and to allow the ERO and entities to appropriately allocate resources.”
63
44
Similar to the purpose of Reliability Standard PRC-015-1, the purpose of currently
effective Reliability Standard PRC-016-1 is “[t]o ensure that all Remedial Action Schemes
(RAS) are properly designed, meet performance requirements, and are coordinated with other
protection systems. To ensure that maintenance and testing programs are developed and
misoperations are analyzed and corrected.” Under this standard, however, responsible entities
are required to analyze and record RAS operations, take corrective actions to avoid future
misoperations, and provide documentation regarding RAS operation analyses to the relevant
Regional Reliability Organizations and NERC as necessary. As these performance requirements
are important to establishing an effective and successful RAS program, NERC proposes to move
these obligations to Requirements R5, R6, and R7 of proposed Reliability Standard PRC-012-2.
Under proposed Requirements R5, R6, and R7, the RAS-entity must analyze RAS operations and
provide the results of that analysis to the relevant RC, design a CAP to address any issues
identified by the RC, and implement the CAP. The RC, as the entity with the wide-area
perspective, is the appropriate entity to oversee RAS, maintain data relevant to operations, use
this data to assist responsible entities in operating reliability, and intervene when necessary.
V.
EFFECTIVE DATE
NERC respectfully requests that the Commission approve Reliability Standard PRC-012-
2 as effective on the first day of the first calendar quarter that is thirty-six (36) months after
appropriate governmental approval, pursuant to the respective Implementation Plan included as
Exhibit C herein. The Implementation Plan provides additional instructions for specific initial
performance obligations of certain entities under Requirements R4, R8, and R9 to address any
ambiguity that may exist for initial performance obligations related to existing RAS or to RAS
designated as “limited impact,” and to address responsibilities related to the creation of a RAS
database.
45
The proposed implementation period of thirty-six (36) months for PRC-012-2 is
appropriate because the affected RCs may choose to redesign the Regional approval processes
currently in existence, which will require considerable time and resources. When establishing a
new system for reviewing and approving RAS under proposed PRC-012-2, the RC would be
required to develop significant infrastructure, including hiring experts to perform any services
that the responsible entities do not currently have available. Entities may desire to continue
using existing regional processes to review RAS, but this would still require entities to establish
contractual relationships with regional volunteers participating in existing regional processes.
Responsible entities would need a thirty-six month implementation period to lay the foundation
for an effective, efficient RAS review process to meet obligations under proposed Reliability
Standard PRC-012-2.
As written, three of the Requirements, Requirements R4, R8, and R9, are recurring or
periodic requirements. As such, the Implementation Plan for PRC-012-2 includes special
instructions for the initial implementation of three Requirements. First, Requirement R4 requires
the PC to evaluate each RAS every five years. For those RAS that are already in service at the
time of implementation and operating as an integrated component of the BES, the
Implementation Plan for PRC-012-2, attached herein as Exhibit C, explains that the PC must
perform the initial performance evaluation of each existing RAS within five (5) years after the
effective date of PRC-012-2. In addition, the PC must perform the initial evaluation of each
“new or functionally modified RAS” within five (5) years after the date that the reviewing RC
approves the RAS.
Second, Requirement R8 requires the RAS-entity to perform a functional test on a
periodic basis according to whether the RC has designated the RAS as “limited impact.” For
46
added clarity, the Implementation Plan for PRC-012-2 explicitly states that responsible entities
must perform the initial functional test of RAS not designated as “limited impact” at least once
within six (6) years after the effective date of PRC-012-2 and at least once within twelve (12)
years after the effective date if the RAS has been designated as “limited impact.”
Finally, certain RCs may not have an established RAS database as anticipated under
Requirement R9 and thus may not be able to “update” the database as mandated under that
Requirement. The Implementation Plan for PRC-012-2 explains (i) that the initial obligation for
RCs without established RAS databases is to establish a database by the effective date of PRC012-2, and (ii) that the first obligation for all RCs under Requirement R9 must be fulfilled within
12 months of the effective date of PRC-012-2.
47
VI.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve
NERC’s Proposal regarding (i) proposed Reliability Standard PRC-012-2 in Exhibit B; (ii) the
Implementation Plan for PRC-012-2 in Exhibit C; (iii) the VRFs and VSLs in Exhibit D; (iv)
retirement of currently effective Reliability Standards PRC-015-1 and PRC-016-1, and (v)
withdrawal of Reliability Standards PRC-012-1, PRC-013-1, and PRC-014-1.
Respectfully submitted,
/s/ Andrew C. Wills
Charles A. Berardesco
Senior Vice President and General Counsel
Shamai Elstein
Senior Counsel
Andrew C. Wills
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: August 5, 2016
48
Exhibit A
Examples of WECC Local Area Protection Systems (LAPS) and
NPCC Type III Remedial Action Schemes
Exhibit A: Examples of WECC Local Area Protection Systems (LAPS) and NPCC Type III RAS
WECC Local Area Protection Systems 1
Scheme Name
Design Objectives
(Contingencies and
system conditions for
which the scheme was
designed)
Operation
(The actions taken by the scheme in
response to Disturbance conditions)
Modeling
(Information on detection logic or
relay settings that control operation
of the scheme)
Unit Dropping
Scheme
Loss of 345 kV line
Trip generation units to avoid thermal
overload of 138 kV line and 230/138 kV
transformers
Shed generation for loss of either end
of 345 kV line
138 kV Line
tripping
Scheme is designed to
eliminate overload on the
138 kV line during loss of
345 kV line
Open 138 kV Line
during loss of 345 kV line to eliminate
overload on the 138 kV line
Transfer trip scheme that will trip the
138 kV line for loss of the 345 kV line
115kV
Overload SPS
Prevent overload of
115kV lines in the event
of a double line outage of
and two 115kV lines.
Opens circuit breaker (CB) 122 and CB
123 which will shed substation load
Open Clear CB 122 and CB 123 if
Clear CB 113 and CB 112 are open,
and CB 122 and CB 123 are loaded
above 215A
The RAS actions at Generation Station
are as follows:
Cold
Prevent overload of
500/230kV T1
Transformer
Trips or ramps back generation at
Generation Station to prevent overload of
the 500/230kV T1 Transformer for a 500
kV single line outage, or a #1 and #2
500kV double line outage.
(1) Trip generation to 0 MW level for
500/230kV T1 transformer
emergency overload condition and #1
and #2 500kV double line outage.
(2) Trip generation to 300 MW level
for 500/230kV T1 transformer
emergency overload condition and
500kV line outage.
(3) Ramp back generation for
500/230kV T1 transformer normal
overload condition and 500kV line
outage.
Sargent
Winter Lake
1
Thermal overload of the
220 kV Line following N-2
loss of the Units 3 and 4,
220 kV lines
Loss of 345 kV line with
heavy southbound
schedule (> ~ 350 MW)
on Path XX.
Pre-selected Units 5-8 are tripped to
relieve the thermal overload
Line loss logic for the critical line
terminals, EMS performs arming
calculations every four seconds.
Trip line terminal (#123) for flow > 650 A
lasting longer than 8000 cycles
Detect line flow > 650 A with fixed
delay of 8000 cycles (2 m 13 s)
The WECC LAPS examples have been redacted to protect Critical Energy Infrastructure Information data and any
other Confidential Information.
NPCC Type III Local SPS Examples 2
Type 3
Generation Rejection
Transmission Cross
Tripping
Generation Rejection
Reason for Installation
Reclosing Breaker may result in
damaging shaft torques on
Generator Unit
Prevent low voltage and
overloads on the Maine 115 kV
system Canadian source
contingency with a line out of
service
Overload protection of two
underground cables and two
overhead lines
Generation Rejection
Prevent thermal overload to
the remaining line in service
Load Rejection
Prevent overloading a 115 kV
line
Initiating Condition
Action Resulting
345 kV Breaker open due to
line relaying.
Open Generator Breaker
>80 MW reverse power flow on
a Maine Autotransformer
Trip the Orrington T1
Autotransformer
Overload of either of two
parallel 115 kV lines.
Runback a generating Unit to
150 MW
Loss of a 115 kV line with
overcurrent on the remaining
parallel line
Loss of Double Circuit Tower
Lines
Runback a generating unit to
168 MW
Trip load and disable
automatic transfer of load
2
The NPCC Type III Local SPS examples have been redacted to protect Critical Energy Infrastructure Information
data and any other confidential information.
3
*Note-the majority of Type III SPS (Limited Impact RAS) installed are Generation Rejection schemes installed to
alleviate local overloads for specific system conditions and contingencies.
Exhibit B
Proposed Reliability Standard PRC-012-2
PRC-012-2 – Remedial Action Schemes
A. Introduction
1.
Title:
Remedial Action Schemes
2.
Number:
PRC-012-2
3.
Purpose:
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Planning Coordinator
4.1.3. RAS-entity – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC-012-2.
B. Requirements and Measures
R1.
Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS-entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to each RAS-entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS-entity in accordance with Requirement R2.
R3.
Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability Coordinator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
Page 1 of 49
PRC-012-2 – Remedial Action Schemes
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
R4.
Each Planning Coordinator, at least once every five full calendar years, shall:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for which
it was designed.
4.1.2. The RAS avoids adverse interactions with other RAS, and protection and
control systems.
4.1.3. For limited impact 1 RAS, the inadvertent operation of the RAS or the
failure of the RAS to operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations.
4.1.4. Except for limited impact RAS, the possible inadvertent operation of the
RAS, resulting from any single RAS component malfunction satisfies all of
the following:
4.1.4.1.
The BES shall remain stable.
4.1.4.2.
Cascading shall not occur.
4.1.4.3.
Applicable Facility Ratings shall not be exceeded.
4.1.4.4.
BES voltages shall be within post-Contingency voltage limits
and post-Contingency voltage deviation limits as established
by the Transmission Planner and the Planning Coordinator.
4.1.4.5.
Transient voltage responses shall be within acceptable limits
as established by the Transmission Planner and the Planning
Coordinator.
4.1.5. Except for limited impact RAS, a single component failure in the RAS,
when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and
conditions for which the RAS is designed.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
1
Page 2 of 49
PRC-012-2 – Remedial Action Schemes
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS-entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
R5.
Each RAS-entity, within 120 full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.1. The System events and/or conditions appropriately triggered the RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with participating RAS-entities and the reviewing Reliability Coordinator(s) in
accordance with Requirement R5.
R6.
Each RAS-entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Longterm Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency pursuant to Requirement R5,
Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS-entity in
accordance with Requirement R6.
Page 3 of 49
PRC-012-2 – Remedial Action Schemes
R7.
Each RAS-entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long-term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the reviewing Reliability
Coordinator(s) that documents the implementation, updating, or completion of a CAP
in accordance with Requirement R7.
R8.
Each RAS-entity shall participate in performing a functional test of each of its RAS to
verify the overall RAS performance and the proper operation of non-Protection
System components: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
•
At least once every six full calendar years for all RAS not designated as limited
impact, or
•
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis for a correct RAS segment or an end-to-end
operation (Measure M5 documentation), or dated documentation demonstrating that
a functional test of each RAS segment or an end-to-end test was performed in
accordance with Requirement R8.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
Page 4 of 49
PRC-012-2 – Remedial Action Schemes
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS-entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1, R3, R5, R6, R7, and R8, and Measures M1, M3, M5, M6, M7,
and M8 since the last audit, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M2 and M9 since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS-entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non-compliant, it shall
keep information related to the non-compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
Page 5 of 49
PRC-012-2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS-entity failed to
provide the information
identified in Attachment 1 to
each Reliability Coordinator
prior to placing a new or
functionally modified RAS in
service or retiring an existing
RAS in accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30 full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90 full
calendar days.
Page 6 of 49
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS-entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS in
service or retiring an existing
RAS in accordance with
Requirement R3.
R4.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 90 full
calendar days.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1.1 through 4.1.5.
Page 7 of 49
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate two or more of
the Parts 4.1.1 through 4.1.5.
OR
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
R5.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by less than or
equal to 10 full calendar
days.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to address one of the
Parts 5.1.1 through 5.1.4.
Page 8 of 49
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 30 full
calendar days.
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to address two or
more of the Parts 5.1.1
through 5.1.4.
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
(Part 5.2) to one or more of
the reviewing Reliability
Coordinator(s).
OR
The RAS-entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10 full calendar days.
Page 9 of 49
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30 full
calendar days.
OR
The RAS-entity developed a
Corrective Action Plan but
failed to submit it to one or
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
more of its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6.
OR
The RAS-entity failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS-entity implemented N/A
a CAP in accordance with
Requirement R7, Part 7.1,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed, or failed
to notify (Part 7.3) each of
the reviewing Reliability
Coordinator(s) of the
updated CAP or completion
of the CAP.
N/A
The RAS-entity failed to
implement a CAP in
accordance with
Requirement R7, Part 7.1.
R8.
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by less than
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 60 full calendar days
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 90 full calendar days.
Page 10 of 49
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 30 full calendar days
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
R9.
Moderate VSL
High VSL
or equal to 30 full calendar
days.
but less than or equal to 60
full calendar days.
but less than or equal to 90
full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30 full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
Page 11 of 49
Severe VSL
OR
The RAS-entity failed to
perform the functional test
for a RAS as specified in
Requirement R8.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90 full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
PRC-012-2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
0
Date
Action
February 8, 2005 Adopted by the Board of Trustees
March 16, 2007
Identified by Commission as “fill-in-the-blank” with
no action taken on the standard
1
November 13,
2014
Adopted by the Board of Trustees
1
November 19,
2015
Accepted by Commission for informational
purposes only
2
May 5, 2016
Adopted by Board of Trustees
0
Page 12 of 49
Change Tracking
New
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified 2 RAS that the RAS-entity must document and provide to
the reviewing Reliability Coordinator(s) (RC). If an item on this list does not apply to a
specific RAS, a response of “Not Applicable” for that item is appropriate. When RAS are
submitted for functional modification review and approval, only the proposed modifications
to that RAS require review; however, the RAS-entity must provide a summary of the existing
functionality. The RC may request additional information on any aspect of the RAS as well as
any reliability issue related to the RAS. Additional entities (without decision authority) may
be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one-line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre- and post-modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS-entity and contact information.
c. Expected or actual in-service date; most recent RC-approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under- or overvoltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
f. Action(s) to be taken by the RAS.
g. Identification of limited impact 3 RAS.
h. Any additional explanation relevant to high-level understanding of the RAS.
Functionally modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
3 A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
2
Page 13 of 49
Attachments
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS-entity proposal and justification for limited impact designation, if applicable.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
8. Identification of other affected RCs.
Page 14 of 49
Attachments
III. Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in service or is being
maintained.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective.
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS-entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
Page 15 of 49
Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability-related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified 4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any aspect of the RAS as well as any reliability issue related to the RAS. If a
checklist item is not relevant to a particular RAS, it should be noted as “Not Applicable.” If
reliability considerations are identified during the review, the considerations and the proposed
resolutions should be documented with the remaining applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The designed timing of RAS operation(s) is appropriate to its BES performance
objectives.
3. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
4. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
5. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate, have been identified.
6. Determination whether or not the RAS is limited impact. 5 A RAS designated as limited
impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations.
7. Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
Functionally modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
5 A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
4
Page 16 of 49
Attachments
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
8. The effects of future BES modifications on the design and operation of the RAS have
been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. Except for limited impact RAS as determined by the RC, a single component failure in a
RAS does not prevent the BES from meeting the same performance requirements as
those required for the events and conditions for which the RAS is designed.
3. The RAS design facilitates periodic testing and maintenance.
4. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
Page 17 of 49
Attachments
Attachment 3
Database Information
1. RAS name.
2. Each RAS-entity and contact information.
3. Expected or actual in-service date; most recent RC-approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under- or over-voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact 6 RAS.
8. Any additional explanation relevant to high-level understanding of the RAS.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
6
Page 18 of 49
Supplemental Material
Technical Justification
4.1.1 Reliability Coordinator
The Reliability Coordinator (RC) is the best-suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide
Area purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS-entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best-suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS-entity
The RAS-entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RASentity has sole responsibility for all the activities assigned within the standard to the RAS-entity.
If the RAS (RAS components) have more than one owner, then each separate RAS component
owner is a RAS-entity and is obligated to participate in various activities identified by the
Requirements.
The standard does not stipulate particular compliance methods. RAS-entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS-entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS-entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Limited impact
RAS are unique and customized assemblages of protection and control equipment that vary in
complexity and impact on the reliability of the BES. These differences in RAS design, action, and
risk to the BES are identified and verified within the construct of Requirements R1-R4 of PRC012-2.
The reviewing RC has the authority to designate a RAS as limited impact if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
Page 19 of 49
Supplemental Material
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The reviewing RC makes the final determination as to whether a RAS qualifies for
the limited impact designation based upon the studies and other information provided with the
Attachment 1 submittal by the RAS-entity.
The standard recognizes the Local Area Protection Scheme (LAPS) classification in WECC
(Western Electricity Coordinating Council) and the Type III classification in NPCC (Northeast
Power Coordinating Council) as initially appropriate for limited impact designation. The
following information describing the aforementioned WECC and NPCC RAS is excerpted from
the respective regional documentation 7.The drafting team notes that the information below
represents the state of the WECC and NPCC regional processes at the time of this standard
development and is subject to change before the effective date of PRC-012-2.
WECC: Local Area Protection Scheme (LAPS)
A Remedial Action Scheme (RAS) whose failure to operate would NOT result in any of the
following:
•
Violations of TPL-001-WECC-RBP System Performance RBP,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
NPCC: Type III
An SPS whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for
classification:
Significant adverse impact – With due regard for the maximum operating capability of the
affected systems, one or more of the following conditions arising from faults or disturbances,
shall be deemed as having significant adverse impact:
a. system instability;
b. unacceptable system dynamic response or equipment tripping;
c. voltage levels in violation of applicable emergency limits;
d. loadings on transmission facilities in violation of applicable emergency limits;
e. unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and
number of system elements contained will vary based on system characteristics. A local area
may be relatively large geographically with relatively few buses in a sparse system, or be
WECC Procedure to Submit a RAS for Assessment Information Required to Assess the Reliability of a RAS Guideline, Revised
10/28/2013 | NPCC Regional Reliability Reference Directory # 7, Special Protection Systems, Version 2, 3/31/2015
7
Page 20 of 49
Supplemental Material
relatively small geographically with a relatively large number of buses in a densely networked
system.
A RAS implemented prior to the effective date of PRC-012-2 that has been through the regional
review processes of WECC or NPCC and classified as either a Local Area Protection Scheme
(LAPS) in WECC or a Type III in NPCC, is recognized as a limited impact RAS upon the effective
date of PRC-012-2 for the purposes of this standard and is subject to all applicable
requirements.
To propose an existing RAS (a RAS implemented prior to the effective date of PRC-012-2) be
designated as limited impact by the reviewing RC, the RAS-entity must prepare and submit the
appropriate Attachment 1 information that includes the technical justification (evaluations)
documenting that the System can meet the performance requirements (specified in
Requirement R4, Parts 4.1.4 and 4.1.5) resulting from a single RAS component malfunction or
failure, respectively.
There is nothing that precludes a RAS-entity from working with the reviewing RC during the
implementation period of PRC-012-2, in anticipation of the standard becoming enforceable.
However, even if the reviewing RC determines the RAS qualifies as limited impact, the
designation is not relevant until the standard becomes effective. Until then, the existing
regional processes remain in effect as well as the existing RAS classifications or lack thereof.
An example of a scheme that could be recognized as a limited impact RAS is a load shedding or
generation rejection scheme used to mitigate the overload of a BES transmission line. The
inadvertent operation of such a scheme would cause the loss of either a certain amount of
generation or load. The evaluation by the RAS-entity should demonstrate that the loss of this
amount of generation or load, without the associated contingency for RAS operation actually
occurring, is acceptable and not detrimental to the reliability of BES; e.g., in terms of frequency
and voltage stability. The failure of that scheme to operate when intended could potentially
lead to the overloading of a transmission line beyond its acceptable rating. The RAS-entity
would need to demonstrate that this overload, while in excess of the applicable Facility Rating,
is not detrimental to the BES outside the contained area (predetermined by studies) affected by
the contingency.
Other examples of limited impact RAS include:
•
A scheme used to protect BES equipment from damage caused by overvoltage through
generation rejection or equipment tripping.
•
A centrally-controlled undervoltage load shedding scheme used to protect a contained
area (predetermined by studies) of the BES against voltage collapse.
•
A scheme used to trip a generating unit following certain BES Contingencies to prevent
the unit from going out of synch with the System; where, if the RAS fails to operate and
the unit pulls out of synchronism, the resulting apparent impedance swings do not
Page 21 of 49
Supplemental Material
result in the tripping of any Transmission System Elements other than the generating
unit and its directly connected Facilities.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Functional modifications consists of any of the following:
•
Changes to System conditions or Contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original
functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in-kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that uses similar
functions. For instance, if a RAS included a CO-11 relay which was replaced by an IAC-53 relay,
that would be an in-kind replacement. If the CO-11 relay were replaced by a microprocessor
SEL-451 relay that used only the same functions as the original CO-11 relay, that would also be
an in-kind replacement; however, if the SEL-451 relay was used to add new logic to what the
CO-11 relay had provided, then the replacement relay would be a functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. For example, System conditions require a RAS to be armed when the
combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to Requirement
R4, or other assessment, indicates that the arming level should be reduced to 450 MW without
requiring any other RAS changes that would not be a functional modification. Similarly, if a RAS
is designed to shed load to reduce loading on a particular line below 1000 amps, then a change
in the load shedding trigger from 1000 amps to 1100 amps would not be a functional
modification.
Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs to the RAS) and the logic to recognize the specific line outages would
Page 22 of 49
Supplemental Material
change, while the generation reduction (RAS output) requirement may or may not change,
depending on which line is out of service. These required RAS changes would be a functional
modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for such functional modifications
may be identified in several ways including but not limited to the Planning evaluations pursuant
to R4, incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning
assessments related to future additions or modifications of other facilities.
See Item 4a in the Implementation Section of Attachment 1 in the Supplemental Material
section for typical RAS components for which a failure may be considered. The RC has the
discretion to make the final determination regarding which components should be regarded as
RAS components during its review.
To facilitate a review that promotes reliability, the RAS-entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS-entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS-entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RASentity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS-entity(ies). An independent review by a multi-disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the widest
area reliability perspective of all functional entities and an awareness of reliability issues in
Page 23 of 49
Supplemental Material
neighboring RC Areas. This Wide Area purview facilitates the evaluation of interactions among
separate RAS as well as interactions among the RAS and other protection and control systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS-entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement. It is recognized that the RC does not
possesses more information or ability than anticipated by their functional registration as
designated by NERC. The NERC Functional Model is a guideline for the development of
standards and their applicability and does not contain compliance requirements. If Reliability
Standards address functions that are not described in the model, the Reliability Standard
requirements take precedence over the Functional Model. For further reference, please see the
Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
for review. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
Requirement R3
Requirement R3 mandates that each RAS-entity resolve all reliability issues (pertaining to its
RAS) identified during the RAS review by the reviewing Reliability Coordinators. Examples of
reliability issues include a lack of dependability, security, or coordination. RC approval of a RAS
is considered to be obtained when the reviewing RC’s feedback to each RAS-entity indicates
that either no reliability issues were identified during the review or all identified reliability
issues were resolved to the RC’s satisfaction.
Dependability is a component of reliability that is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over-tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability that is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re-configuring the System. Such actions, if inadvertently taken, are undesirable
Page 24 of 49
Supplemental Material
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC012-2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS-entity or the reviewing RC(s) may
have alternative ideas or methods available to resolve the issue(s). In either case, the concern
needs to be resolved in deference to reliability, and the RC has the final decision.
A specific time period for the RAS-entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS-entity to effect a timely
implementation.
A specific time period for the RC to respond to the RAS-entity following the RAS review is also
not necessary because the RC will be aware of (1) any reliability issues associated with the RAS
not being in service and (2) the RAS-entity’s schedule to implement the RAS to address those
reliability issues. Since the RC is the ultimate arbiter of BES operating reliability, resolving
reliability issues is a priority for the RC and serves as an incentive to expeditiously respond to
the RAS-entity.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every five
full calendar years. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it interacts with and impacts the
BES.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate,
cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations. Limited impact RAS are not
subject to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to the
design with minimal benefit to BES reliability.
A RAS implemented after the effective date of this standard can only be designated as limited
impact by the reviewing RC(s). A RAS implemented prior to the effective date of PRC-012-2 that
has been through the regional review processes of WECC or NPCC and is classified as either a
Local Area Protection Scheme (LAPS) in WECC or a Type III in NPCC is recognized as a limited
impact RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
Page 25 of 49
Supplemental Material
Requirement R4 also clarifies that the RAS single component failure and inadvertent operation
tests do not apply to RAS which are determined to be limited impact. Requiring a limited impact
RAS to meet the single component failure and inadvertent operation tests would just add
complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within five full
calendar years of the effective date of PRC‐012‐2. For new or functionally modified RAS, the
initial performance of the requirement must be completed within five full calendar years of the
RAS approval date by the reviewing RC(s). Five full calendar years was selected as the maximum
time frame between evaluations based on the time frames for similar requirements in
Reliability Standards PRC-006, PRC-010, and PRC-014. The RAS evaluation can be performed
sooner if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. System
changes also have the potential to alter the reliability impact of limited impact RAS on the BES.
Requirement 4, Part 4.1.3 explicitly requires the periodic evaluation of limited impact RAS to
verify the limited impact designation remains applicable. The periodic RAS evaluation will
typically lead to one of the following outcomes: 1) affirmation that the existing RAS is effective;
2) identification of changes needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.5) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The PC is the functional entity best suited to perform the
analyses because they have a wide-area planning perspective. To promote reliability, the PC is
required to provide the results of the evaluation to each impacted Transmission Planner and
Planning Coordinator, in addition to each reviewing RC and RAS-entity. In cases where a RAS
crosses PC boundaries, each affected PC is responsible for conducting either individual
evaluations or participating in a coordinated evaluation.
The intent of Requirement R4, Part 4.1.4 is to verify that the possible inadvertent operation of
the RAS (other than limited impact RAS), caused by the malfunction of a single component of
the RAS, meet the same System performance requirements as those required for the
Contingency(ies) or System conditions for which it is designed. If the RAS is designed to meet
one of the planning events (P0-P7) in TPL-001-4, the possible inadvertent operation of the RAS
must meet the same performance requirements listed in the standard for that planning event.
The requirement clarifies that the inadvertent operation to be considered is only that caused by
the malfunction of a single RAS component. This allows features to be designed into the RAS to
improve security, such that inadvertent operation due to malfunction of a single component is
prevented; otherwise, the RAS inadvertent operation must satisfy Requirement R4, Part 4.1.4.
The intent of Requirement R4, Part 4.1.4 is also to verify that the possible inadvertent operation
of the RAS (other than limited impact RAS) installed for an extreme event in TPL-001-4 or for
some other Contingency or System conditions not defined in TPL-001-4 (therefore without
performance requirements), meet the minimum System performance requirements of Category
P7 in Table 1 of NERC Reliability Standard TPL-001-4. However, instead of referring to the TPL
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standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.4.1 – 4.1.4.5) are the ones that are common to all planning events (P0-P7) listed in
TPL-001-4.
With reference to Requirement 4, Part 4.1.4, note that the only differences in performance
requirements among the TPL (P0-P7) events (not common to all of them) concern NonConsequential Load Loss and interruption of Firm Transmission Service. It is not necessary for
Requirement R4, Part 4.1.4 to specify performance requirements related to these areas
because a RAS is only allowed to drop non-consequential load or interrupt Firm Transmission
Service if that action is allowed for the Contingency for which it is designed. Therefore, the
inadvertent operation should automatically meet Non-Consequential Load Loss or interrupting
Firm Transmission Service performance requirements for the Contingency(ies) for which it was
designed.
The intent of Requirement R4, Part 4.1.5 is to verify that a single component failure in a RAS,
other than limited impact RAS, when the RAS is intended to operate, does not prevent the BES
from meeting the same performance requirements (defined in Reliability Standard TPL-001-4 or
its successor) as those required for the events and conditions for which the RAS is designed.
This analysis is needed to ensure that changing System conditions do not result in the single
component failure requirement not being met.
The following is an example of a single component failure causing the System to fail to meet the
performance requirements for the P1 event for which the RAS was installed. Consider the
instance where a three-phase Fault (P1 event) results in a generating plant becoming unstable
(a violation of the System performance requirements of TPL-001-4). To resolve this, a RAS is
installed to trip a single generating unit which allows the remaining units at the plant to remain
stable. If failure of a single component (e.g., relay) in the RAS results in the RAS failing to
operate for the P1 event, the generating plant would become unstable (failing to meet the
System performance requirements of TPL-001-4 for a P1 event).
Requirement R4, Part 4.1.5 does not mandate that all RAS have redundant components. For
example:
•
Consider the instance where a RAS is installed to mitigate an extreme event in TPL-0014. There are no System performance requirements for extreme events; therefore, the
RAS does not need redundancy to meet the same performance requirements as those
required for the events and conditions for which the RAS was designed.
•
Consider a RAS that arms more load or generation than necessary such that failure of
the RAS to drop a portion of load or generation due to that single component failure will
still result in satisfactory System performance, as long as tripping the total armed
amount of load or generation does not cause other adverse impacts to reliability.
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The scope of the periodic evaluation does not include a new review of the physical
implementation of the RAS, as this was confirmed by the RC during the initial review and
verified by subsequent functional testing. However, it is possible that a RAS design which
previously satisfied requirements for inadvertent RAS operation and single component failure
by means other than component redundancy may fail to satisfy these requirements at a later
time, and must be evaluated with respect to the current System. For example, if the actions of a
particular RAS include tripping load, load growth could occur over time that impacts the
amount of load to be tripped. These changes could result in tripping too much load upon
inadvertent operation and result in violations of Facility Ratings. Alternatively, the RAS might be
designed to trip more load than necessary (i.e., “over trip”) in order to satisfy single component
failure requirements. System changes could result in too little load being tripped and
unacceptable BES performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC-004-4 regarding
the investigation of a Protection System Misoperation; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
the RAS-entity(s) is required to provide the results of RAS operational performance analyses to
its reviewing RC(s) if the analyses revealed a deficiency.
The RAS-entity(ies) may need to collaborate with its associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS-entity for a RAS, the RAS-entities would collaborate to conduct and
submit a single, coordinated operational performance analysis.
Requirement R6
RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may be identified
in the periodic RAS evaluation conducted by the PC in Requirement R4, in the operational
analysis conducted by the RAS-entity in Requirement R5, or in the functional test performed by
the RAS-entity(ies) in Requirement R8. To mitigate potential reliability risks, Requirement R6
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mandates that each RAS-entity participate in developing a CAP that establishes the mitigation
actions and timetable necessary to address the deficiency.
The RAS-entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS-entity(ies) may request assistance with development of the
CAP from other parties such as its Transmission Planner or Planning Coordinator; however, the
RAS-entity has the responsibility for compliance with this requirement.
A CAP may require functional changes be made to a RAS. In this case, Attachment 1 information
must be submitted to the reviewing RC(s), an RC review must be performed to obtain RC
approval before the RAS-entity can place RAS modifications in service, per Requirements R1,
R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering or consulting work. A timeframe of six full calendar months is allotted to allow
enough time for RAS-entity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. Ideally, when there is more than one RASentity for a RAS, the RAS-entities would collaborate to develop and submit a single, coordinated
CAP. A RAS deficiency may require the RC or Transmission Operator to impose operating
restrictions so the System can operate in a reliable way until the RAS deficiency is resolved. The
possibility of such operating restrictions will incent the RAS-entity to resolve the issue as quickly
as possible.
The following are example situations of when a CAP is required:
•
A determination after a RAS operation/non-operation investigation that the RAS did not
meet performance expectations or did not operate as designed.
•
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
•
Equipment failures.
•
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
Requirement R7 mandates that each RAS-entity implement its CAP developed in Requirement
R6 which mitigates the deficiencies identified in Requirements R4, R5, or R8. By definition, a
CAP is: “A list of actions and an associated timetable for implementation to remedy a specific
problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. If the CAP is changed, the RAS-entity must notify the reviewing Reliability
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Coordinator(s). The RAS-entity must also notify the Reliability Coordinator(s) when the CAP has
been completed.
The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS-entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non-Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in-service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC-005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed with minimum impact to the
BES and should align with expected results. The RAS-entity is in the best position to determine
the testing procedure and schedule due to their overall knowledge of the RAS design,
installation, and functionality. Periodic testing provides the RAS-entity assurance that latent
failures may be identified and also promotes identification of changes in the System that may
have introduced latent failures.
The six and twelve full calendar year functional testing intervals are greater than the annual or
bi-annual periodic testing performed in some NERC Regions. However, these intervals are a
balance between the resources required to perform the testing and the potential reliability
impacts to the BES created by undiscovered latent failures that could cause an incorrect
operation of the RAS. Longer test intervals for limited impact RAS are acceptable because
incorrect operations or failures to operate present a low reliability risk to the Bulk Power
System.
Functional testing is not synonymous with end-to-end testing. End-to-end testing is an
acceptable method but may not be feasible for many RAS. When end-to-end testing is not
possible, a RAS-entity may use a segmented functional testing approach. The segments can be
tested individually negating the need for complex maintenance schedules. In addition, actual
RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does not
operate in its entirety during a System event or System conditions do not allow an end-to-end
scheme test, then the segmented approach should be used to fulfill this Requirement.
Functional testing includes the testing of all RAS inputs used for detection, arming, operating,
and data collection. Functional testing, by default operates the processing logic and
infrastructure of a RAS, but focuses on the RAS inputs as well as the actions initiated by RAS
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outputs to address the System condition(s) for which the RAS is designed. All segments and
components of a RAS must be tested or have proven operations within the applicable
maximum test interval to demonstrate compliance with the Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC-005, Table 1-1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up to the protective
relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3-8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well-defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component-level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of Contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real-time) to
the Transmission Operator via PRC-001, Requirement R6, then to the RC via TOP-001-3,
Requirement R8. See Phase 2 of Project 2007-06 for the mapping document from PRC-001 to
other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
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is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end-to-end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS-entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
maximum test interval that started on the date of the previous successful test of those (nonoperating) segments in order to be compliant with Requirement R8.
Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available. Attachment 3 contains the minimum information that is
required to be included about each RAS listed in the database. Additional information can be
requested by the RC.
The database enables the RC to provide other entities high-level information on existing RAS
that could potentially impact the operational and/or planning activities of that entity. The
information provided is sufficient for an entity with a reliability need to evaluate whether the
RAS can impact its System. For example, a RAS performing generation rejection to mitigate an
overload on a transmission line may cause a power flow change within an adjacent entity area.
This entity should be able to evaluate the risk that a RAS poses to its System from the high-level
information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS-entity from the RC.
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Process Flow Diagram
The diagram below depicts the process flow of the PRC-012-2 requirements.
New RAS proposed
or RAS modified/
retired
Attachment 1
Attachment 2
R1
RAS-entity submits
RAS to RC for review
R2
RC Review Process
For new, modified,
or removal of RAS
RC Approves RAS as is
R3
RAS-entity accepts
approval
R9
RC updates RAS
database
Modify RAS per RC
direction
RC identified issues
With RAS
R3
RAS-entity
addresses issues
RAS
Database
Proposed alternative
to RC direction
Dated Report /
Analysis
Dated
communications
with RAS-entity(ies)
& RC
Yes
reset 5-year clock
Does CAP identify
RAS modification?
No
RAS 5-year review
R4
PC – 5-year review
of RAS in the
planning area
RAS operation or
non operation as
intended
Any deficiencies
identified?
R5
RAS entity determines if RAS
operated as intended (120 days
or an accepted alternative
schedule)
R6
RAS-entity proposes
Corrective Action
Plan within 6
months
Yes
No
R7
RAS-entity
implement the CAP
and update the CAP
until complete
Dated
documentation of
non operation or
operation not as
intended to RC
No
Work Management
documents
Maintenance
Records
Yes
Dated
documentation to
state correct
operation
Yes
At least once every 6
years (12 years –
limited impact)
R8
Perform functional
test of RAS
Any deficiencies
identified?
No
Dated
documentation of
functional testing
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS-entity(ies) to provide a detailed list of information
describing the RAS to the reviewing RC. If there are multiple RAS-entities for a single RAS,
information will be needed from all RAS-entities. Ideally, in such cases, a single RAS-entity will
take the lead to compile all the data identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide-ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified 8 RAS that the RAS-entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS-entity
provides a summary of the existing RAS functionality.
I. General
1. Information such as maps, one-line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single-line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre- and post-modified functionality of the RAS.
8
Functionally modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
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3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC-012-2, Requirements R5 and R7]
Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name.
b. Each RAS-entity and contact information.
c. Expected or actual in-service date; most recent (Requirement R3) RC-approval date;
most recent five full calendar year (Requirement R4) evaluation date; and, date of
retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under-/over-voltage,
slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (initiating conditions).
f. Corrective action taken by the RAS.
g. Identification of limited impact 9 RAS.
h. Any additional explanation relevant to high level understanding of the RAS.
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II. Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical System
Contingencies or other operating conditions when RAS action is intended to occur.
If no arming conditions are required, this should also be stated.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
9
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c. Event-based RAS are triggered by specific Contingencies that initiate mitigating
action. Condition-based RAS may also be initiated by specific Contingencies, but
specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed. [Reference NEC Reliability Standard PRC-014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS-related operations.
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC-014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. RAS-entity proposal and justification for limited impact designation, if applicable.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of PRC-012-2 that has been through the
regional review processes of WECC or NPCC and is classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited impact
RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
[Reference NERC Reliability Standard PRC-012, R1.4]
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a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC-012, R1.5 and PRC-014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or reconfiguring the System. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available Fault duty,
which can affect distance relay overcurrent (“fault detector”) supervision and ground
overcurrent protection coordination.
8. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be
designed to be secure. Several types of devices have been commonly used as disturbance,
condition, or status detectors:
•
Line open status (event detectors),
•
Protective relay inputs and outputs (event and parameter detectors),
•
Transducer and IED (analog) inputs (parameter and response detectors),
•
Rate of change (parameter and response detectors).
DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by
PRC-005. However, redundant RAS, when used, should be supplied from separately
protected (fused or breakered) circuits.
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Communications: Telecommunications Channels
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non-deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel
or equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS-entity, or
perhaps leased from another entity familiar with the necessary reliability requirements.
All channel equipment should be monitored and alarmed to the dispatch center so that
timely diagnostic and repair action shall take place upon failure. Publicly switched
telephone networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel
working on the channel can readily identify the proper circuit. Channels between
entities should be identified with a common name at all terminals.
Transfer Trip
Transfer trip equipment, when separate from other RAS equipment, should be
monitored and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions
may be required at different arming levels or for different Contingencies. Scheme logic
may be achievable by something as simple as wiring a few auxiliary relay contacts or by
much more complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units
(RTUs), and logic processors. Single-function relays have been used historically to
implement RAS, but this approach is now less common except for very simple new RAS
or minor additions to existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS
actions at the sites where action is required.
Monitoring by SCADA/EMS should include at least
•
Whether the scheme is in service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in service or out of service.
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For RAS that are armed automatically, these two states are independent because
a RAS that has been placed in service may be armed or unarmed based on
whether the automatic arming criteria have been met.
•
The current operational state of the scheme (available or not).
•
In cases where the RAS requires single component failure performance; e.g.,
redundancy, the minimal status indications should be provided separately for each
RAS.
The minimum status is generally sufficient for operational purposes; however,
where possible it is often useful to provide additional information regarding
partial failures or the status of critical components to allow the RAS-entity to
more efficiently troubleshoot a reported failure. Whether this capability exists
will depend in part on the design and vintage of equipment used in the RAS.
While all schemes should provide the minimum level of monitoring, new
schemes should be designed with the objective of providing monitoring at least
similar to what is provided for microprocessor-based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line-charging current;
c. Breaker trip coil current monitoring—typically used when high-speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of the
aforementioned, out of step, etc. are dependent on specific scheme requirements,
but some forms may substitute for or enhance other monitoring described in items
‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in service or is being
maintained.
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In this context, a multifunction device (e.g., microprocessor-based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor-based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi-function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective. [Reference NERC Reliability Standard PRC-012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement.
Acceptable methods to achieve this objective include, but are not limited to the
following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
Protective or auxiliary relays used by the RAS.
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Supplemental Material
ii.
Communications systems necessary for correct operation of the RAS.
iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation due to that single component failure will still result in
satisfactory System performance, as long as tripping the total armed amount of load
or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re-dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS-entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies and technical justifications, if applicable, upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Supplemental Material
Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent-wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability-related considerations relevant to various aspects of RAS design and
implementation.
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
•
The name used to identify the RAS.
2. Each RAS-entity and contact information.
•
A reliable phone number or email address should be included to contact each RAS-entity
if more information is needed.
3. Expected or actual in-service date; most recent (Requirement R3) RC-approval date; most
recent five full calendar year (Requirement R4) evaluation date; and, date of retirement, if
applicable.
•
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under-/over-voltage, slow voltage
recovery).
•
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the Contingencies or System conditions for which the RAS was designed
(initiating conditions).
•
A high level summary of the conditions/Contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
•
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
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7. Identification of limited impact 10 RAS.
•
Specify whether or not the RAS is designated as limited impact.
8. Any additional explanation relevant to high-level understanding of the RAS.
•
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
10
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Supplemental Material
Rationale
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its action(s)
can have a significant impact on the reliability and integrity of the Bulk Electric System (BES).
Therefore, a review of a proposed new RAS or an existing RAS proposed for functional
modification or retirement; i.e., removal from service must be completed prior to
implementation or retirement.
Functional modifications consist of any of the following:
•
Changes to System conditions or Contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original
functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS-entity must provide the reviewer with
sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS-entity provide them to the reviewing Reliability Coordinator (RC). The RC
(reviewing RC) that coordinates the area where the RAS is located is responsible for the review.
Ideally, when there is more than one RAS-entity for a RAS, the RAS-entities would collaborate
and submit a single, coordinated Attachment 1 to the reviewing RC. In cases where a RAS
crosses RC Area boundaries, each affected RC is responsible for conducting either individual
reviews or participating in a coordinated review.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the RAS
review because it has the widest area operational and reliability perspective of all functional
entities and an awareness of reliability issues in any neighboring RC Area. This Wide Area
purview facilitates the evaluation of interactions among separate RAS as well as interactions
among RAS and other protection and control systems. Review by the RC also minimizes the
possibility of a conflict of interest that could exist because of business relationships among the
RAS-entity, Planning Coordinator (PC), Transmission Planner (TP), or other entities that are
likely to be involved in the planning or implementation of a RAS. The RC is not expected to
possess more information or ability than anticipated by their functional registration as
designated by NERC. The RC may request assistance to perform RAS reviews from other parties
such as the PC or regional technical groups; however, the RC will retain the responsibility for
compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each submitted RAS. The
time frame of four full calendar months is consistent with current utility and regional practice;
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Supplemental Material
however, flexibility is provided by allowing the RC(s) and RAS-entity(ies) to negotiate a mutually
agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s) in
which it is located.
Rationale for Requirement R3: The RC review is intended to identify reliability issues that must
be resolved before the RAS can be put in service. Examples of reliability issues include a lack of
dependability, security, or coordination.
A specific time period for the RAS-entity to respond to the reviewing RC following identification
of any reliability issue(s) is not necessary because the RAS-entity wants to expedite the timely
approval and subsequent implementation of the RAS.
A specific time period for the RC to respond to the RAS-entity following the RAS review is also
not necessary because the RC will be aware of (1) any reliability issues associated with the RAS
not being in service and (2) the RAS-entity’s schedule to implement the RAS to address those
reliability issues. Since the RC is the ultimate arbiter of BES operating reliability, resolving
reliability issues is a priority for the RC and serves as an incentive to expeditiously respond to
the RAS-entity.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS be
performed at least once every five full calendar years. The purpose of the periodic RAS
evaluation is to verify the continued effectiveness and coordination of the RAS, as well as to
verify that, if a RAS single component malfunction or single component failure were to occur,
the requirements for BES performance would continue to be satisfied. A periodic evaluation is
required because changes in System topology or operating conditions may change the
effectiveness of a RAS or the way it impacts the BES.
RAS are unique and customized assemblages of protection and control equipment that vary in
complexity and impact on the reliability of the BES. In recognition of these differences, RAS can
be designated by the reviewing RC(s) as limited impact. A limited impact RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The “BES” qualifier in the preceding statement modifies all of the conditions that
follow it. Limited impact RAS are not subject to the RAS single component malfunction and
failure tests of Parts 4.1.4 and 4.1.5, respectively. Requiring a limited impact RAS to meet these
tests would add complexity to the design with minimal benefit to BES reliability. See the
Supplemental Material for more on the limited impact designation.
The standard recognizes the Local Area Protection Scheme (LAPS) classification in WECC
(Western Electricity Coordinating Council) and the Type III classification in NPCC (Northeast
Power Coordinating Council) as initially appropriate for limited impact designation. A RAS
implemented prior to the effective date of PRC-012-2 that has been through the regional
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Supplemental Material
review processes of WECC or NPCC and is classified as either a Local Area Protection Scheme
(LAPS) in WECC or a Type III in NPCC is recognized as a limited impact RAS upon the effective
date of PRC-012-2 for the purposes of this standard and is subject to all applicable
requirements.
For existing RAS, the initial performance of Requirement R4 must be completed within five full
calendar years of the effective date of PRC‐012‐2. For new or functionally modified RAS, the
initial performance of the requirement must be completed within five full calendar years of the
RAS approval date by the reviewing RC(s). Five full calendar years was selected as the maximum
time frame between evaluations based on the time frames for similar requirements in
Reliability Standards PRC-006, PRC-010, and PRC-014. The RAS evaluation can be performed
sooner if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. System
changes also have the potential to alter the reliability impact of limited impact RAS on the BES.
Requirement 4, Part 4.1.3 explicitly requires the periodic evaluation of limited impact RAS to
verify the limited impact designation remains applicable; the PC can use its discretion as to how
this evaluation is performed. The periodic RAS evaluation will typically lead to one of the
following outcomes: 1) affirmation that the existing RAS is effective; 2) identification of changes
needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.5) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The Planning Coordinator (PC) is the functional entity best
suited to perform this evaluation because they have a wide area planning perspective. To
promote reliability, the PC is required to provide the results of the evaluation to each impacted
Transmission Planner and Planning Coordinator, in addition to each reviewing RC and RASentity. In cases where a RAS crosses PC boundaries, each affected PC is responsible for
conducting either individual evaluations or participating in a coordinated evaluation.
The previous version of this standard (PRC-012-1 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL-001-0, TPL002-0, and TPL-003-0) as that required of the Contingency for which it was designed, and not
exceed TPL-003-0.” Requirement R4 clarifies that the inadvertent operation to be considered
would only be that caused by the malfunction of a single RAS component. This allows security
features to be designed into the RAS such that inadvertent operation due to a single
component malfunction is prevented. Otherwise, consistent with PRC-012-1 Requirement 1,
R1.4, the RAS should be designed so that its whole or partial inadvertent operation due to a
single component malfunction satisfies the System performance requirements for the same
Contingency for which the RAS was designed.
If the RAS was installed for an extreme event in TPL-001-4 or for some other Contingency or
System condition not defined in TPL-001-4 (therefore without performance requirements), its
inadvertent operation still must meet some minimum System performance requirements.
However, instead of referring to the TPL-001-4, Requirement R4 lists the System performance
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Supplemental Material
requirements that the inadvertent operation must satisfy. The performance requirements listed
(Parts 4.1.4.1 – 4.1.4.5) are the ones that are common to all planning events P0-P7 listed in TPL001-4.
Rationale for Requirement R5: The correct operation of a RAS is important for maintaining the
reliability and integrity of the BES. Any incorrect operation of a RAS indicates that the RAS
effectiveness and/or coordination has been compromised. Therefore, all operations of a RAS
and failures of a RAS to operate when expected must be analyzed to verify that the RAS
operation was consistent with its intended functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation was consistent
with the implemented design; or 2) identify RAS performance deficiencies that manifested in
the incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC-004-4 regarding
the investigation of a Protection System Misoperation. To promote reliability, each RAS-entity is
required to provide the results of RAS operational performance analyses that identified any
deficiencies to its reviewing RC(s).
RAS-entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS-entity for a RAS, the RAS-entities would collaborate to conduct and
submit a single, coordinated operational performance analysis.
Rationale for Requirement R6: Deficiencies identified in the periodic RAS evaluation conducted
by the PC pursuant to Requirement R4, in the operational performance analysis conducted by
the RAS-entity pursuant to Requirement R5, or in the functional test performed by the RASentity pursuant to Requirement R8, potentially pose a reliability risk to the BES. To mitigate
these potential reliability risks, Requirement R6 mandates that each RAS-entity develop a
Corrective Action Plan (CAP) to address the identified deficiency. The CAP contains the
mitigation actions and associated timetable necessary to remedy the specific deficiency. The
RAS-entity may request assistance with CAP development from other parties such as its
Transmission Planner or Planning Coordinator; however, the RAS-entity has the responsibility
for compliance with this requirement.
If the CAP requires that a functional change be made to a RAS, the RAS-entity will need to
submit information identified in Attachment 1 to the reviewing RC(s) prior to placing RAS
modifications in service per Requirement R1.
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Supplemental Material
Depending on the complexity of the identified deficiency(ies), development of a CAP may
require studies, and other engineering or consulting work. A maximum time frame of six full
calendar months is specified for RAS-entity collaboration on the CAP development. Ideally,
when there is more than one RAS-entity for a RAS, the RAS-entities would collaborate to
develop and submit a single, coordinated CAP.
Rationale for Requirement R7: Requirement R7 mandates each RAS-entity implement a CAP
(developed in Requirement R6) that mitigates the deficiencies identified in Requirements R4,
R5, or R8. By definition, a CAP is: “A list of actions and an associated timetable for
implementation to remedy a specific problem.” The implementation of a properly developed
CAP ensures that RAS deficiencies are mitigated in a timely manner. Each reviewing Reliability
Coordinator must be notified if CAP actions or timetables change, and when the CAP is
completed.
Rationale for Requirement R8: Due to the wide variety of RAS designs and implementations,
and the potential for impacting BES reliability, it is important that periodic functional testing of
a RAS be performed. A functional test provides an overall confirmation of the RAS to operate as
designed and verifies the proper operation of the non-Protection System (control) components
of a RAS that are not addressed in PRC-005. Protection System components that are part of a
RAS are maintained in accordance with PRC-005.
The six or twelve full calendar year test interval, which begins on the effective date of the
standard pursuant to the PRC-012-2 implementation plan, is a balance between the resources
required to perform the testing and the potential reliability impacts to the BES created by
undiscovered latent failures that could cause an incorrect operation of the RAS. Extending to
longer intervals increases the reliability risk to the BES posed by an undiscovered latent failure
that could cause an incorrect operation or failure of the RAS. The RAS-entity is in the best
position to determine the testing procedure and schedule due to its overall knowledge of the
RAS design, installation, and functionality. Functional testing may be accomplished with end-toend testing or a segmented approach. For segmented testing, each segment of a RAS must be
tested. Overlapping segments can be tested individually negating the need for complex
maintenance schedules and outages.
The maximum allowable interval between functional tests is six full calendar years for RAS that
are not designated as limited impact RAS and twelve full calendar years for RAS that are
designated as limited impact RAS. The interval between tests begins on the date of the most
recent successful test for each individual segment or end-to-end test. A successful test of one
segment only resets the test interval clock for that segment. A correct operation of a RAS
qualifies as a functional test for those RAS segments which operate (documentation for
compliance with Requirement R5 Part 5.1). If an event causes a partial operation of a RAS, the
segments without an operation will require a separate functional test within the maximum
interval with the starting date determined by the previous successful test of the segments that
did not operate.
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Supplemental Material
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS existing
in a Reliability Coordinator Area. The database enables the RC to provide other entities highlevel information on existing RAS that could potentially impact the operational and/or planning
activities of that entity. Attachment 3 lists the minimum information required for the RAS
database, which includes a summary of the RAS initiating conditions, corrective actions, and
System issues being mitigated. This information allows an entity to evaluate the reliability need
for requesting more detailed information from the RAS-entities identified in the database
contact information. The RC is the appropriate entity to maintain the database because the RC
receives the required database information when a new or modified RAS is submitted for
review. The twelve full calendar month time frame is aligned with industry practice and allows
sufficient time for the RC to collect the appropriate information from RAS-entities and update
the RAS database.
Page 49 of 49
Exhibit C
Implementation Plan for PRC-012-2
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
• PRC-012-2 – Remedial Action Schemes
Requested Withdrawals
• PRC-012-1 – Remedial Action Scheme Review Procedure
•
PRC-013-1 – Remedial Action Scheme Database
•
PRC-014-1 – Remedial Action Scheme Assessment
Requested Retirements
• PRC-015-1 – Remedial Action Scheme Data and Documentation
•
PRC-016-1 – Remedial Action Scheme Misoperations
Applicable Entities
• Reliability Coordinator
•
Planning Coordinator
•
RAS-entity – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part
of a RAS
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for Remedial
Action Scheme (“RAS”) and associated revisions to related Reliability Standards to consolidate that term
with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC-012-0, PRC-013-0, and PRC-014-0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not enforceable,
NERC revised these standards to account for the RAS definition revision and changed relevant version
numbers to reflect the change. Because of this change, NERC requested retirement of PRC-012-0, PRC013-0, and PRC-014-0, and provided, for informational purposes only, updated Reliability Standards PRC012-1, PRC-013-1, and PRC-014-1. In the same Petition, NERC requested retirement of PRC-015-0 and PRC016-0.1 and approval of Reliability Standards PRC-015-1 and PRC-016-1, again implementing changes
stemming from the revised definition of RAS.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards.
General Considerations
Reliability Standard PRC-012-2 was developed to consolidate previously unapproved standards which
were designated by the Commission as “fill-in-the-blank” standards and to revise other RAS-related
standards. Reliability Standard PRC-012-2 also provides clear and unambiguous responsibilities to the
specific users, owners, and operators of the Bulk-Power System. Reliability Standard PRC-012-2 establishes
a new working framework between RAS-entities, PCs, and RCs, and this new framework will involve
considerable start-up effort. As such, implementation of Reliability Standard PRC-012-2 will occur over a
thirty six (36) month period after approval of the standard by applicable governmental authorities.
Limited Impact RAS
A RAS implemented prior to the effective date of PRC-012-2 that has been through the regional review
processes of WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC or a
Type III in NPCC is recognized as a limited impact RAS upon the effective date of PRC-012-2 and is subject
to all applicable requirements.
Effective Date
Where approval by an applicable governmental authority is required, Reliability Standard PRC-012-2 shall
become effective on the first day of the first calendar quarter that is thirty six (36) months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Provisions concerning the initial performance of
obligations under Requirements R4, R8, and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is thirty six (36) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Provisions concerning the initial performance of obligations under Requirements R4, R8, and R9 are
outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within five
(5) full calendar years after the effective date of PRC‐012‐2, as described above.
For new or functionally modified RAS, the initial performance of Requirement R4 must be completed within
five (5) full calendar years after the date that the RAS is approved by the reviewing RC(s) under Requirement
R3.
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Page 2 of 3
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years after the effective date for PRC-012-2, as
described above.
For each RAS designated as limited impact, initial performance of obligations under Requirement R8 must
be completed at least once within twelve (12) full calendar years after the effective date for PRC-012-2, as
described above.
Requirement R9
For each Reliability Coordinator that does not have a RAS database, the initial obligation under
Requirement R9 is to establish a database by the effective date of PRC-012-2.
Each Reliability Coordinator will perform the obligation of Requirement R9 within twelve full calendar
months after the effective date of PRC-012-2, as described above.
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the effective date of PRC-0122 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Page 3 of 3
Exhibit D
Analysis of Violation Risk Factors and Violation Severity Levels for PRC-012-2
Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – 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.
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to provide
the information identified in
Attachment 1 to each Reliability
Coordinator prior to placing a
new or functionally modified
RAS in service or retiring an
existing RAS in accordance with
Requirement R1.
6
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30 full calendar days
but less than or equal to 60 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60 full calendar days
but less than or equal to 90 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90 full calendar days.
OR
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
10
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in
service or retiring an existing
RAS in accordance with
Requirement R3.
14
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirement R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 90 full
calendar days.
OR
OR
The Planning Coordinator
The Planning Coordinator
performed the evaluation in
performed the evaluation in
accordance with Requirement
accordance with Requirement
R4, but failed to evaluate two or
R4, but failed to evaluate one of more of the Parts 4.1.1 through
the Parts 4.1.1 through 4.1.5.
4.1.5.
OR
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
receiving entities listed in Part
4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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21
VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
less than or equal to 10 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 10 full calendar days
but less than or equal to 20 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 20 full calendar days
but less than or equal to 30 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 30 full calendar days.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1.1
through 5.1.4.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1.1 through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
22
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
23
VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
24
VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
25
VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10 full calendar days.
Moderate
High
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10 full calendar days but less
than or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20 full calendar days but less
than or equal to 30 full calendar
days.
Severe
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30 full calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
26
VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐entity failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
27
VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
28
VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
29
VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐entity implemented a
N/A
CAP in accordance with
Requirement R7, Part 7.1, but
failed to update the CAP (Part
7.2) if actions or timetables
changed, or failed to notify (Part
7.3) each of the reviewing
Reliability Coordinator(s) of the
updated CAP or completion of
the CAP.
ifications for PRC‐012‐2, Requirement R7
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
High
N/A
Severe
The RAS‐entity failed to
implement a CAP in accordance
with Requirement R7, Part 7.1.
30
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
31
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
32
VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
33
VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 90 full
calendar days.
OR
The RAS‐entity failed to perform
the functional test for a RAS as
specified in Requirement R8.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
34
VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
35
VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
36
VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
37
VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30 full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30 full calendar days but less
than or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60 full calendar days but less
than or equal to 90 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than 90
full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
38
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document
39
Exhibit E
Mapping Document for PRC-012-2
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
R1.1. Description of the process for submitting a
proposed RAS for Regional Reliability
Organization review.
R1.2. Requirements to provide data that describes
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
shall be designed so that a single RAS
component failure, when the RAS was
intended to operate, does not prevent the
interconnected transmission system from
meeting the performance requirements
defined in Reliability Standards TPL-001-0,
TPL-002-0, and TPL-003-0.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC-012-1 R.1.1:
Covered by Requirements R1,
R2 and R3
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC-012-1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC-012-1 R.1.3:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.5
PRC-012-1 R.1.4:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2, and
Requirement R4, Part 4.1.4
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was
designed, and not exceed TPL-003-0.
PRC-012-1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
R1.5. Requirements to demonstrate the proposed
RAS will coordinate with other protection
and control systems and applicable Regional
Reliability Organization Emergency
procedures.
PRC-012-1 R.1.6:
Covered by Requirement R5
Existing Requirement in Reliability Standard
R1.6. Regional Reliability Organization definition
of misoperation.
R1.7. Requirements for analysis and
documentation of corrective action plans for
all RAS misoperations.
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-012-1 R.1.7:
Covered by Requirements R5
and R6
PRC-012-1 R.1.8:
PRC-012-2 NERC Standards
Development Process
PRC-012-1 R.1.9:
Covered by Requirement R8
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS-entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
4
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
performance and the proper operation of non-Protection
System components:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
•
At least once every six full calendar years for all
RAS not designated as limited impact, or
•
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-013-1 R1:
Covered by Requirement R9
PRC-013-1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-014-1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-014-1 R2:
Covered by Requirement R4
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
PRC-014-1 R3:
Covered by Requirement R4
R3.1. Identification of group conducting the assessment
and the date the assessment was performed.
PRC-014-1 R3.1 - R3.4:
Covered by Requirement R4
R3.2. Study years, system conditions, and contingencies
analyzed in the technical studies on which the
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-014-1 R3.5:
Covered by Requirement R6
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non-compliant
RAS.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
11
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall maintain
a list of and provide data for existing and proposed
RAS as specified in Reliability Standard PRC-013-1
R1.
PRC-015-1 R1:
Covered by Requirement R1,
Attachment 1
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC-012-1_R1 prior to being placed in
service.
PRC-015-1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
Retired P81
N/A
13
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC-012-1_R1.
Translation to New
Standard or Other Action
PRC-016-1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-016-1 R2:
Covered by Requirements R6
and R7
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
PRC-016-1 R3:
Covered by Requirements R5,
R6, and R7, Attachment 1
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
17
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
Mapping Document
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
18
Exhibit F
Reliability Standard PRC-012-2 Remedial Action Schemes
Question & Answer Document
Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
April 2016
Table of Contents
Question & Answer for PRC-012-2 .............................................................................................................................2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ............................2
2. Why is the five year evaluation of Requirement R4 assigned to the Planning Coordinator? .............................2
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ..........3
4. Why do RAS need to be reviewed and approved by a group other than the RAS-entity? .................................3
5. What is required for RAS “single component failure” and why? ........................................................................3
6. What is required for RAS “inadvertent operation” and why? ............................................................................4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ..............................................................................................................................................................5
8. Why are RAS classifications not recognized in the standard? ............................................................................5
9. What constitutes a functional modification of a RAS? .......................................................................................6
Attachment A – Project Roster…………………………………………………………………………………………………………………………….7
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
Question & Answer | April 2016
1
Question & Answer for PRC-012-2
The Project 2010-05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC-012-2.
1.
Why is the Remedial Action Scheme (RAS) review assigned to the
Reliability Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk-Power System. The NERC white paper suggested
Reliability Coordinators (RCs) and Planning Coordinators (PCs) for RAS-review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best-suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. The Wide Area purview better facilitates
the evaluation of interactions among separate RAS, as well as interactions among RAS and other
protection and control systems. The selection of the RC also minimizes the possibility of a conflict
of interest that could exist because of business relationships among the RAS-entity, Planning
Coordinator, Transmission Planner, or other entities involved in the planning or implementation
of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain
objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2.
Why is the five year evaluation of Requirement R4 assigned to the
Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least once every five full
calendar years to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
2
3.
Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP-1-3 Requirement R13 requires Balancing Authorities (BA) and Transmission Operators (TOP)
to perform operational reliability assessments (e.g., real time contingency analysis (RTCA), dayahead, seasonal) that include data describing new or degraded RAS. In addition, IRO-005-4
requires RCs to share any pertinent data, such as data from RAS, with potentially affected BAs
and TOPs. Operating horizon assessments that include RAS are already required by other
standards, so an additional requirement duplicating that effort is not necessary.
TPL-001-4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near-term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short-term (annual) planning horizon assessments are already
required by the TPL-001-4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS-entities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why?
The existing PRC-012-1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.5 and
Attachment 1 of PRC-012-2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL-001-4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
•
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
3
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
•
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
•
Using alternative automatic actions to back up failures of single RAS components.
•
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re-dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC-012-2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review processes and designated as
Type III in NPCC or Local Area Protection Scheme (LAPS) in WECC will be recognized as limited
impact. When appropriate, new or functionally modified RAS implemented after the effective
date of this standard will be designated as limited impact by the Reliability Coordinator during
the RAS review process. Limited impact schemes are not subject to the single component failure
aspect of Requirement R4, Part 4.1.5.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC-012-1 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the contingency for which
it was designed and not exceed TPL-003-0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.4 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL-001-4 or for System conditions
not defined in TPL-001-4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.4.1 – 4.1.4.5, which are the
performance requirements common to all planning events P0–P7.
Within the RAS review process of PRC-012-2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
4
date of this standard that has been through the regional review processes and designated as
Type III in NPCC or LAPS in WECC will be recognized as limited impact. When appropriate, new or
functionally modified RAS implemented after the effective date of this standard will be
designated as limited impact by the Reliability Coordinator in conjunction with the RAS review
process. Limited impact schemes are not subject to the single component malfunction aspect of
Requirement R4, Part 4.1.4.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific System configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post-Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS-SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC-012-1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.5 and Attachment 1, item III.4
of PRC-012-2 that relates to single component failure; consequently, there is no need to have a
formal classification for this purpose.
Similarly, the standard drafting team concluded that the SPCS-SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC012-1, and problematic due to the difficulty of drawing a universally satisfactory delineation in
generally worded classification criteria. Within the RAS review process of PRC-012-2, there is a
provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation,
angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the regional
review processes and designated as Type III in NPCC or LAPS in WECC will be recognized as
limited impact. When appropriate, new or functionally modified RAS implemented after the
effective date of this standard will be designated as limited impact by the Reliability Coordinator
in conjunction with the RAS review process.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
5
9.
What constitutes a functional modification of a RAS?
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of
existing components
• Changes to RAS logic beyond correcting existing errors
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS-entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor that carries RAS communication when such changes may be
important to the timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component, or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation logic.
The Supplemental Material section of Reliability Standard PRC-012-2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
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Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles-Eric Langlois
Hydro-Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
7
Exhibit G
Order No. 672 Criteria
Order No. 672 Criteria
In Order No. 672, the Commission identified a number of 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.1 The discussion below identifies these
factors and explains how the revisions reflected in proposed Reliability Standard has met or
exceeded the criteria.
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal.2
The proposed Reliability Standard PRC 012-2, attached as Exhibit B, achieves specific
reliability goals using sound methods to achieve those goals. The purpose of proposed
Reliability Standard PRC 012-2—Remedial Action Schemes is “to ensure that Remedial Action
Schemes (“RAS”) do not introduce unintentional or unacceptable reliability risks to the Bulk
Electric System (“BES”).” Proposed Reliability Standard PRC 012-2 accomplishes its goal by
establishing requirements for Reliability Coordinators (“RC”), Planning Coordinators (“PC”),
and RAS-entities to manage RAS connected to the BES by reviewing, evaluating, analyzing,
testing, and addressing issues associated with each RAS.
Existing effective Reliability Standards require RAS owners to collect data regarding each of
their RAS, analyze RAS operations, and take corrective actions to avoid misoperations.
However, reliability would be improved by instituting requirements on affected entities to
periodically review and maintain RAS and to collect relevant information about each RAS.
Proposed Reliability Standard PRC-012-2 would accomplish these goals by ensuring (i) that the
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at PP 321, 324.
RC, as the entity with a widest area perspective, reviews and approves each RAS before placing
the RAS into operation, (ii) that affected entities periodically review, test, and evaluate each
RAS, and (iii) that the RC maintains a database of each RAS in its RC area. By using a defensein-depth approach, the proposed Reliability Standard improves the reliability of the BES.
2. Proposed Reliability Standards must be applicable only to users, owners, and
operators of the Bulk Power System, and must be clear and unambiguous as to what
is required and who is required to comply.3
The proposed Reliability Standard is applicable only to users, owners, and operators of the
Bulk Power System and is clear and unambiguous as to what is required and who is to comply,
in accordance with Order No. 672. The proposed Reliability Standard applies to the Reliability
Coordinator, Planning Coordinator, and RAS entities.4 The proposed Reliability Standard
clearly states who is required to comply with the standard and what is required, in accordance
with Order No. 672.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.5
The Violation Risk Factor (“VRF”) and Violation Severity Level (“VSL”) for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment.
The assignment of the severity level of each VSL is consistent with the corresponding
Requirement and will ensure uniformity and consistency in the determination of penalties. The
VSLs do not use any ambiguous terminology, thereby supporting uniformity and consistency in
the determination of similar penalties for similar violations. For these reasons, the proposed
3
Order No. 672, at PP 322, 325.
Section 4 of PRC-012-2 explains that a RAS-entity is “the Transmission Owner, Generator Owner, or
Distribution Provider that owns all or part of a RAS.”
5
Order No. 672 at P 327.
4
Reliability Standard includes clear an understandable consequences in accordance with Order
No. 672.
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced with consistence and with no
preference.6
The proposed Reliability Standard contains Measures that support each Requirement by
clearly identifying what is required to demonstrate compliance and how the Requirement will be
enforced. The Measures are as follows:
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment
1documentation and the dated communications with the reviewing Reliability Coordinator(s)
in accordance with Requirement R1.
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with the RASentity in accordance with Requirement R2.
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues were
identified during the review or that all identified reliability issues were resolved in
accordance with Requirement R3.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS entity(ies), Transmission Planner(s), Planning Coordinator(s),
and the reviewing Reliability Coordinator(s) in accordance with Requirement R4.
M5. Acceptable evidence may include, but is not limited to, dated documentation
detailing the results of the RAS operational performance analysis and dated communications
with participating RAS-entities and the reviewing Reliability Coordinator(s) in accordance
with Requirement R5.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS-entity in
accordance with Requirement R6.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, setting sheets, work orders,
maintenance records, and communication with the reviewing Reliability Coordinator(s) that
6
Order No. 672 at P 327.
documents the implementation, updating, or completion of a CAP in accordance with
Requirement R7.
M8. Acceptable evidence may include, but is not limited to, dated documentation
detailing the RAS operational performance analysis for a correct RAS segment or an end-toend operation (Measure M5 documentation), or dated documentation demonstrating that a
functional test of each RAS segment or an end-to-end test was performed in accordance with
Requirement R8.
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in accordance
with Requirement R9.
The above Measures work in coordination with the respective Requirements to ensure that
the Requirements will each be enforced in a clear, consistent, and non-preferential manner
without prejudice to any party.
5. 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 or historical regional infrastructure design.7
Proposed Reliability Standard PRC 012-2 achieves the reliability goals effectively and
efficiently in accordance with Order No. 672. The proposed Reliability Standard improves
reliability by instituting oversight measures for RAS, thus creating a continent-wide RAS
program to improve communications and security associated with these devices. The proposed
Reliability Standard will also establish a new working framework between RAS-entities, PCs,
and RCs that establishes clear responsibilities and results in a new efficient system that prevents
risks to the reliability of the Bulk Power System.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability.8
7
8
Order No. 672, at P 328.
Order No. 672, at PP 329-330.
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed standard represents significant benefits for the
reliability of the Bulk Power System because it institutes Requirements that will lead to a
decrease in risk to the BES through review, testing, evaluations, and improvements to RAS. In
doing so, the proposed Reliability Standard does not sacrifice excellence in operating system
reliability for costs associated with implementation of the Reliability Standard.
7. 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 geographic area or regional model. It should take into account
regional variations in the organization 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.9
The proposed Reliability Standard applies throughout North America and does not favor one
geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability.10
The proposed Reliability Standard has no undue negative effect on competition nor results in
any unnecessary restrictions.
9. The implementation time for the proposed Reliability Standard is reasonable.11
The proposed effective date for the standard is just and reasonable and appropriately balances
the urgency in the need to implement the standard against the reasonableness of the time allowed
9
Order No. 672, at P 331.
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.
11
Order No. 672, at P 333.
10
for those who must comply to develop necessary procedures, software, facilities, staffing or other
relevant capability. NERC proposes an effective date for PRC-012-2 on the first day of the first
calendar quarter that is thirty-six (36) months after the effective date of the applicable regulatory
approval. The proposed implementation period is designed to allow sufficient time for the
applicable entities to make any changes in their staffing or internal processes necessary to
implement the proposed review, evaluation, and testing procedures. The proposed effective date
is explained in the proposed Implementation Plan, attached as Exhibit C.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process.12
The proposed Reliability Standard was developed in accordance with NERC’s Commission
approved, ANSI-accredited processes for developing and approving Reliability Standards. 13
Exhibit H includes a summary of the standard development proceedings, and details the
processes followed to develop the Reliability Standard. These processes included, among other
things, multiple comment periods, pre-ballot review periods, and balloting periods. Additionally,
all meetings of the standard drafting team were properly noticed and open to the public.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.14
NERC has not identified competing public interests regarding the request for approval of the
proposed Reliability Standard PRC 012-2. No comments were received that indicated the
proposed Reliability Standard conflict with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors.15
12
Order No. 672, at P 334.
See NERC Rules of Procedure, Section 300 (Reliability Standards Development) and Appendix 3A
(Standard Processes Manual).
14
Order No. 672, at P 335.
15
Order No. 672, at P 323.
13
No other factors relevant to whether the proposed Reliability Standard PRC 012-2 are just
and reasonable were identified.
Exhibit H
Summary of Development History and Complete Record of Development
Summary of Development History
The development record for proposed Reliability Standard PRC-012-2 is summarized
below.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give
“due weight” to the technical expertise of the ERO.1 The technical expertise of the ERO is
derived from the standard drafting team selected to lead each project in accordance with Section
4.3 of the NERC Standards Process Manual.2 For this project, the standards drafting team
consisted of industry experts, all with a diverse set of experiences. A roster of the standard
drafting team members is included in Exhibit I.
II.
Standard Development History
A.
Standards Authorization Request Development
On February 12, 2014, NERC submitted a Standard Authorization Request (“SAR”) to
the NERC Standards Committee (“SC”) to revise the NERC Glossary definition for Special
Protection System (“SPS”) and to revise or develop SPS-related Reliability Standards. The SC
authorized the posting of the SAR for Project 2010-05.2 on February 12, 2014, and NERC
posted the SAR for a 30-day comment period from February 18, 2014 through March 19, 2014.
NERC later divided the work anticipated by the SAR for Project 2010-05.2 into two phases,
Project 2010-05.2 and Project 2010-05.3, to address NERC Glossary definition revisions ahead
of developing a Reliability Standard for planning, coordination, and design of Remedial Action
Schemes (“RAS”).
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d)(2) (2012).
The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
2
B.
Unofficial Comment Period
Proposed Reliability Standard PRC-012-2 was posted for an initial comment period from
April 30, 2015 through May 20, 2015.3
C.
First Posting - Comment Period and Initial Ballot
After the unofficial comment period, the first official draft of proposed Reliability
Standard PRC-012-2 was posted for a 45-day public comment period from August 20, 2015,
through October 5, 2015, with an initial ballot and non-binding poll held from September 25,
2015, through October 5, 2015. Several documents were posted with the first draft, including the
Implementation Plan for Reliability Standard PRC-012-2, an associated Question and Answer
Document, the Mapping Document for PRC-012-2, and the Violation Risk Factor and Violation
Severity Level Justification Document. There were 60 responses, including comments from
approximately 155 different people, and approximately 104 different companies representing
nine of the ten Industry Segments.4 The initial ballot reached quorum at 83.96% of the ballot
pool and received votes of approval from 48.11% of the voters.
D.
Second Posting – Comment Period and Additional Ballot
Proposed Reliability Standard PRC-012-2 was posted for a 45-day formal comment
period from November 25, 2015, through January 8, 2018, with an additional parallel 10-day
ballot and Non-binding Poll held from December 30, 2015, until January 8, 2016. Updated
versions of the associated Implementation Plan, Question and Answer Document, Mapping
Document, and the Violation Risk Factor and Violation Severity Level Justification Document
3
NERC, Survey Report, Project 2010-05.3 (May 20, 2015) available at
http://www.nerc.com/pa/Stand/Prjct201005_3RmdialActnSchmsPhase3ofPrtctnSystmsDL/201005.3_Phase_3_of%20Protection_Systems_RAS_Comments_Received_Report_05272015.pdf.
4
NERC, Consideration of Comments, Project 2010-05.3 (Nov. 25, 2015), available at
http://www.nerc.com/pa/Stand/Prjct201005_3RmdialActnSchmsPhase3ofPrtctnSystmsDL/2010-05_3_RAS_PRC012-2_Consideration_of_Comments_11252015_final.pdf.
were also posted with the second draft. There were 46 responses, including comments from
approximately 150 different people from approximately 98 different companies representing nine
of the ten Industry Segments.5 The additional ballot reached quorum at 83.39% of the ballot
pool and received votes of approval from 60.39% of the voters.
E.
Third Posting – Comment Period and Additional Ballot
Proposed Reliability Standard PRC-012-2 was posted for a 45-day formal comment
period from February 3, 2016, through March 18, 2016, with an additional parallel ballot held
from March 9, 2016 through March 18, 2016. Updated versions of the associated
Implementation Plan, the Question and Answer Document, Mapping Document, Violation Risk
Factor and Violation Severity Level Justification Document, and Unofficial Comment Form
were also posted with the third draft. There were 43 sets of responses, including comments from
approximately 41 different people, approximately 39 companies representing eight of the
Industry Segments.6 The additional ballot reached quorum at 75.55% of the ballot pool and
received votes of approval from 78.87% of the voters.
F.
Final Ballot
Proposed Reliability Standard PRC-012-2 was posted for a 10-day final ballot period
from April 20, 2016, through April 29, 2016. The proposed Reliability Standard received
adequate votes for approval, reaching quorum at 81.19% of the ballot body and receiving votes
of approval from 80.36% of the voters.7
5
NERC, Consideration of Comments, Project 2010-05.3 (Feb. 3, 2016), available at
http://www.nerc.com/pa/Stand/Prjct201005_3RmdialActnSchmsPhase3ofPrtctnSystmsDL/2010-05_3_RAS_PRC012-2_C_of_C_02032016.pdf.
6
NERC, Consideration of Comments, Project 2010-05.3 (Apr. 20, 2016), available at
http://www.nerc.com/pa/Stand/Prjct201005_3RmdialActnSchmsPhase3ofPrtctnSystmsDL/201005.3_RAS_Comments_Received_Report_03222016.pdf.
7
NERC, Standards Announcement, Project 2010-05.3, available at
http://www.nerc.com/pa/Stand/Prjct201005_3RmdialActnSchmsPhase3ofPrtctnSystmsDL/2010-05.3_PRC-0122_FB_Results_Word_Announce_05032016.pdf.
G.
Board of Trustees Adoption
Proposed Reliability Standard PRC-012-2 was adopted by the NERC Board of Trustees
on May 5, 2016.
Complete Record of Development
Program Areas & Departments > Standards > Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Related Files | 2010-05.2 Phase 2 of Protection Systems
Status
Final ballots for PRC-012-2 – Remedial Action Schemes and the Revised Definition of "Special Protection System" concluded 8 p.m. Eastern, Friday, April 29, 2016. The voting results can be accessed via the
links below. The standard and definition will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
Background
In early 2011, NERC staff decided to divide Project 2010-05: Protection Systems into phases. Phase 1 addressed the Misoperations of Protection Systems and was adopted by the NERC BOT on August 14, 2014. Phase 2
revised the definition of Remedial Action Scheme (RAS) and was adopted by the NERC BOT on November 13, 2014. Phase 3 is intended to address all aspects of RAS and Special Protection Systems (SPS) contained in the
RAS/SPS-related Reliability Standards.
In FERC Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and PRC-014-0 as “fill-in-the-blank” standards and did not approve or remand them because they are applicable to the
Regional Reliability Organizations (RROs), assigning the RROs the responsibility to establish regional procedures and databases, and to assess and document the operation, coordination, and compliance of RAS/SPS. The
deference to regional practices precludes the consistent application of RAS/SPS-related Reliability Standard requirements. Although there is no FERC directive associated with Phase 3; this project will consider
recommendations from the joint report, Special Protection Systems (SPS) and Remedial Action Schemes (RAS): Assessment of Definition, Regional Practices, and Application of Related Standards, issued by the System
Analysis and Modeling Subcommittee (SAMS) and System Protection and Control Subcommittee (SPCS), as well as from the joint FERC-NERC inquiry of the September 2011 Southwest Blackout Event.
Standard(s) affected - PRC-012-1, PRC-013-1, PRC-014-1, PRC-015-1, PRC-016-1
Purpose/Industry Need
RAS/SPS are designed to detect predetermined System conditions and automatically take corrective actions to protect the reliability and integrity of the Bulk Electric System; consequently, the NERC Reliability Standards
pertaining to these schemes should provide clear and unambiguous performance expectations and reliability benefits.
To accomplish this, the Phase 3 drafting team will correct the applicability of the fill-in-the-blank standards by assigning the requirement responsibilities to the specific users, owners, and operators of the Bulk-Power
System; and will revise the RAS/SPS-related standards that address the:
•
planning, coordination, and design of RAS/SPS,
•
review, assessment, and documentation of RAS/SPS,
•
analysis of RAS/SPS operation(s) and/or failure(s) to operate and corrective actions,
•
testing of RAS/SPS, and maintenance of any non-protection system components used.
Draft
Final Draft
PRC-012-2
Clean (71) | Redline to Last Posted (72)
Actions
Dates
Results
Summary (86)
Final Ballots
Ballot Results
Implementation Plan
Clean (73) | Redline to Last Posted (74)
Info (85)
04/20/16 - 04/29/16
PRC-012-2 (87)
Vote
Definition of Special Protection System
Clean (75) | Redline to Last Posted (76)
Definition (88)
Consideration of
Comments
Implementation Plan
Clean (77) | Redline to Last Posted (78)
Supporting Materials
Mapping Document
Clean (79) | Redline to Last Posted (80)
VRF/VSL Justification
Clean (81) | Redline to Last Posted (82)
Q&A
Clean (83) | Redline to Last Posted (84)
Draft 3
PRC-012-2
Clean (53) | Redline to Last Posted (54)
Additional Ballot and Nonbinding Poll
Info (64)
Implementation Plan
Clean (55) | Redline to Last Posted (56)
Vote
Comment Period
Supporting Materials
Info (65)
Unofficial Comment Form (Word) (57)
Submit Comments
Summary (66)
03/09/16 - 03/18/16
Non-binding Poll
Results (68)
02/03/16 - 03/18/16
Mapping Document
Clean (58) | Redline to Last Posted (59)
VRF/VSL Justification
Clean (60) | Redline to Last Posted (61)
Q&A
Clean (62) | Redline to Last Posted (63)
Draft Reliability Standard Audit Worksheet (RSAW)
Info
Send RSAW feedback to:
[email protected]
Ballot Results (67)
02/17/16 - 03/18/16
Comments Received
(69)
Consideration of
Comments (70)
Draft 2
PRC-012-2
Clean (31) | Redline to Last Posted (32)
Proposed Definition of Special Protection System (33)
Implementation Plan - PRC-012-2
Clean (34) | Redline to Last Posted (35)
PRC-012-2
Additional Ballot and Nonbinding Poll
Definition
Initial Ballot
Summary (47)
Ballot Results
12/30/15 - 01/08/16
PRC-012-2 (48)
Definition (49)
Updated Info (44)
Non-binding Poll
(50)
Info (45)
Implementation Plan – Definition (36)
Vote
Supporting Materials
Comment Period
Unofficial Comment Form (Word) (37)
Info (46)
Mapping Document
Clean (38) | Redline to Last Posted (39)
11/25/15 - 01/08/16
Comments Received
(51)
Submit Comments
VRF/VSL Justification
Clean (40) | Redline to Last Posted (41)
Q&A
Clean (42) | Redline to Last Posted (43)
Info
Send RSAW feedback to:
12/09/15 - 01/08/16
[email protected]
Draft Reliability Standard Audit Worksheet (RSAW)
Draft 1
PRC-012-2 (17)
Initial Ballot and Non-binding
Poll
Updated Info (23)
Implementation Plan (18)
Info (24)
Supporting Materials
Vote
Unofficial Comment Form (Word) (19)
Summary (26)
09/25/15 - 10/05/15
Ballot Results (27)
Non-binding Poll
Results (28)
Consideration of
Comments (52)
Mapping Document (20)
Comment Period
VRF/VSL Justification (21)
Info (25)
08/20/15 - 10/05/15
Comments Received
(29)
Q & A (22)
Submit Comments
Join Ballot Pools
08/20/15 - 09/18/15
Draft RSAW
Info
Send RSAW feedback to:
09/03/15 - 10/05/15
[email protected]
Draft 1
PRC-012-2 (7)
Supporting Materials
Unofficial Comment Form (Word) (8)
SCPS Technical Report (9)
PRC-012-1 (10)
PRC-013-1 (11)
PRC-014-1 (12)
PRC-015-1 (13)
PRC-016-1 (14)
Comment Period
Info (15)
Submit Comments
04/30/15 - 05/20/15
Comments Received
(16)
Consideration of
Comments (30)
Project 2010-05.2 Phase 2 of Protection Systems Reference Material
Standard Authorization Request (1)
Supporting Materials
Unofficial Comment Form (Word) (2)
SPCS Technical Report (3)
PRC Project Coordination Plan (4)
Comment Period
Info (5)
Submit Comments
02/18/14 - 03/19/14
Comments Received
(6)
Standards Authorization Request Form
When completed, email this form to:
[email protected]
For questions about this form or for assistance in
completing the form, call Valerie Agnew at 404446-2566.
NERC welcomes suggestions for improving the
reliability of the Bulk-Power System through
improved Reliability Standards. Please use this form
to submit your proposal for a new NERC Reliability
Standard or a revision to an existing standard.
Request to propose a new or a revision to a Reliability Standard
Proposed Project Number
and Name
Project 2010-05.2 – Special Protection Systems (Phase 2 of Protection
Systems)
Proposed Project Purpose:
Revise NERC Glossary of Terms definition: Special Protection System (SPS)
Revise SPS-related Reliability Standards
Date Submitted:
02/12/2014
SAR Requester Information
Name:
Al McMeekin
Organization:
NERC
Telephone:
404-446-9675
E-mail:
[email protected]
SAR Type (Check as many as applicable)
New Standard
Withdrawal of existing Standard
Revision to existing Standard
Urgent Action
Standards Authorization Request Form
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
The existing NERC Glossary of Terms definition for a Special Protection System (SPS) or, as used in the
Western Interconnection, a Remedial Action Scheme (RAS), lacks the clarity and specificity necessary for
consistent identification and classification of protection schemes as SPS or RAS across the eight NERC
Regions, leading to inconsistent application of the related NERC Reliability Standards.
In FERC Order No. 693 (dated March 16, 2007), the Commission identified three of the SPS-related
standards (PRC-012-0, PRC-013-0, and PRC-014-0) as fill-in-the-blank standards because they are
applicable to the Regional Reliability Organizations (RROs). Consequently, the Commission did not
approve or remand them, rendering them neither mandatory nor enforceable.
This project also addresses, in part, four recommendations related to identification and coordination of
SPS from the joint FERC-NERC inquiry of the September 2011 Southwest Blackout Event.
NOTE: Detailed information is included in the NERC Planning Committee report “Special Protection
Systems (SPS) and Remedial Action Schemes (RAS): Assessment of Definition, Regional Practices, and
Application of Related Standards” Revision 0.1 – April 2013.
Purpose or Goal (How does this request propose to address the problem described above?):
1)
2)
3)
Establish a definition of an SPS that provides the specificity needed to consistently identify and
classify protection schemes as SPS or RAS across all eight NERC Regions, thereby promoting the
consistent application of the NERC Reliability Standards related to SPS.
Correct the applicability of the NERC Reliability Standards related to SPS by assigning
responsibilities to the specific users, owners, and operators of the Bulk-Power System rather than
the RROs.
Develop continent-wide standards to address all aspects of SPS, including but not limited to, the:
• planning, coordination, and design of SPS,
• review, assessment, and documentation of SPS,
• operational considerations for monitoring, status notification, and response to failures,
• analysis of SPS operations, and defining and reporting of SPS misoperations,
• testing of SPS and maintenance of non-protection system components used in SPS.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
Successful implementation of a modified SPS definition and revised SPS standards will improve Bulk-
2
Standards Authorization Request Form
SAR Information
Power System reliability by providing continent-wide consistency in the identification and classification
of SPS and the application of NERC Reliability Standards related to SPS.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The project will develop a revised definition of SPS or RAS, as well as standards that address the:
•
•
•
•
•
review of new or modified SPS,
annual assessments of SPS in transmission planning studies,
periodic comprehensive SPS assessments,
analysis and reporting of SPS misoperations,
maintenance, testing and operational aspects of SPS.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
The SDT will revise the definition of SPS to provide the clarity and specificity necessary for consistent
identification and classification of protection schemes as SPS or RAS across the eight NERC Regions.
The SDT will revise or retire the six existing SPS standards:
•
•
•
•
•
•
PRC-012-0 Special Protection System Review Procedure
PRC-013-0 Special Protection System Database
PRC-014-0 Special Protection System Assessment
PRC-015-0 Special Protection System data and Documentation
PRC-016-0.1 Special Protection System Misoperations
PRC-017-0 Special Protection System Maintenance and Testing
The SDT will correct the applicability in PRC-012-0, PRC-013-0, and PRC-014-0 by assigning the
requirements to the specific users, owners, and operators of the bulk power system.
The SDT will combine appropriate requirements from PRC-012-0, PRC-013-0, PRC-014-0, and PRC-015-0
into a Reliability Standard The new standard will provide specific requirements for:
•
•
•
•
review of new or modified SPS;
annual assessments of SPS in transmission planning studies;
periodic comprehensive SPS assessments;
design of SPS; and
3
Standards Authorization Request Form
SAR Information
•
coordination of SPS with other SPS, UFLS, UVLS, and Protection Systems.
Due to the significant difference between Protection Systems and SPS, the subject of SPS misoperation
is not addressed in the revision of Reliability Standard PRC-004. This SDT will develop a definition for SPS
misoperation and revise PRC-016-0.1. The new Reliability Standard will provide specific requirements
for the analysis of SPS operations and reporting of SPS misoperations.
The SDT will address the complexity of maintaining and testing SPS, as well as the maintenance and
testing of non-Protection System components used in SPS in a Reliability Standard. This SDT will
coordinate with the PRC-005-4 SDT to prevent any overlaps or gaps in coverage.
The SDT also will consider operational considerations for monitoring, status notification, and response
to failures of SPS; and, if necessary, modify other related standards.
The SDT will retire requirements that are administrative in nature that are not necessary for reliability of
the Bulk-Power System, or that are superseded by other requirements; i.e., the new Reliability
Standards will qualify as steady-state.
No market interface impacts are anticipated.
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
4
Standards Authorization Request Form
Reliability Functions
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
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
5
Standards Authorization Request Form
Reliability and Market Interface Principles
4.
5.
6.
7.
8.
reliably.
Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Related Standards
Standard No.
Explanation
IRO-005-3.1a
The SDT may decide not to change this standard, but the SDT should keep the
standard in mind since it contains potentially overlapping requirements.
PRC-001-1.1
The SDT may decide not to change this standard, but the SDT should keep the
standard in mind since it contains potentially overlapping requirements.
PRC-005-2
The SDT may decide not to change this standard, or subsequently approved
versions, but the SDT should keep the standard in mind to avoid any gaps or
overlap between this standard and PRC-017-1.
6
Standards Authorization Request Form
Related Standards
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
7
Unofficial Comment Form
Project 2010-05.2 – Special Protection Systems (Phase 2 of Protection
Systems) – SAR
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard Authorization Request (SAR). The electronic comment form must be
completed by 8 p.m. ET March 19, 2014.
If you have questions please contact [email protected] via email or by telephone at 404-446-9675.
The project page may be accessed by clicking here. (Please insert link to new project page)
Background Information
In early 2011, NERC staff decided to divide the approved project for Protection System Misoperations into
two phases. Phase 1 of Project 2010-05 is addressing Misoperations of Protection Systems; the project
began in April, 2011 and is ongoing. Project 2010-05.2 Special Protection Systems is Phase 2 of Protection
Systems and will address all aspects of Special Protection Systems including misoperations of SPS. In FERC
Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and PRC-014-0
as “fill-in-the-blank” standards and did not approve or remand them because they are applicable to the
Regional Reliability Organizations (RROs); consequently, they are not mandatory or enforceable. This
project proposes to correct the applicability by assigning responsibilities to the specific users, owners, and
operators of the Bulk-Power System. The existing NERC Glossary of Terms definition for a Special
Protection System (SPS) or Remedial Action Scheme (RAS), as used in the Western Interconnection, lacks
the clarity and specificity necessary for consistent identification and classification of protection schemes
as SPS or RAS across the eight NERC Regions. This leads to inconsistent application of the SPS-related
Reliability Standards. At the request of the NERC Standards Committee, the Planning Committee directed
the System Protection and Control Subcommittee (SPCS) to research this issue. The SPCS authored the
attached report and provided a draft definition of SPS for consideration in the standards development
process. This project proposes to establish a definition for SPS that provides the needed specificity to
promote the consistent application of the NERC Reliability Standards related to SPS. This project also
proposes to address, in part, four recommendations related to identification and coordination of SPS from
the joint FERC-NERC inquiry of the September 2011 Southwest Blackout Event. There is no FERC directive
associated with the SPS project: however, this project is being coordinated with Project 2008-02 UVLS,
which does have an associated directive in P 1509 of Order No. 693 to modify PRC-010-0. These projects
are linked because the proposed definition for Special Protection Systems must be written relative to the
proposed definition of UVLS Program.
Questions
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
1. Do you have any specific questions or comments relating to the scope of the proposed SAR?
Yes
No
Comments:
2. If you are aware of the need for a regional variance or business practice that should be considered
with this phase of the project, please identify it here.
Yes
No
Comments:
3. If you have any other comments on this SAR that you haven’t already mentioned, please provide
them here:
Comments:
Special Protection Systems (SPS)
and Remedial Action Schemes (RAS):
Assessment of Definition, Regional
Practices, and Application of Related
Standards
Revision 0.1 – April 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
404-446-2560
| www.nerc.com
1 of 48
NERC’s Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory authority established to enhance
the reliability of the bulk power system in North America. NERC develops and enforces Reliability Standards; assesses
adequacy annually via a ten-year forecast and winter and summer forecasts; monitors the bulk power system; and
educates, trains, and certifies industry personnel. NERC is the electric reliability organization for North America, subject to
1
oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.
NERC assesses and reports on the reliability and adequacy of the North American bulk power system, which is divided into
eight Regional areas, as shown on the map and table below. The users, owners, and operators of the bulk power system
within these areas account for virtually all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte,
México.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce
Reliability Standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those
standards mandatory and enforceable. In Canada, NERC presently has memorandums of understanding in place with
provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the Canadian National
Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law.
NERC has an agreement with Manitoba Hydro making reliability standards mandatory for that entity, and Manitoba has
recently adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators
in the province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s
Transportation Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending.
NERC and NPCC have been recognized as standards-setting bodies by the Régie de l’énergie of Québec, and Québec has the
framework in place for reliability standards to become mandatory. NERC’s reliability standards are also mandatory in Nova
Scotia and British Columbia. NERC is working with the other governmental authorities in Canada to achieve equivalent
recognition.
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
2 of 48
Table of Contents
NERC’s Mission ............................................................................................................................................................................ 2
Table of Contents ......................................................................................................................................................................... 3
Executive Summary ..................................................................................................................................................................... 5
Introduction ................................................................................................................................................................................. 6
Problem Statement .................................................................................................................................................................. 6
Background .............................................................................................................................................................................. 6
NERC Definitions .................................................................................................................................................................. 6
NERC Reliability Standards ................................................................................................................................................... 7
Chapter 1 – SPS Definition ........................................................................................................................................................... 8
Considerations for a Revised Definition .................................................................................................................................. 8
Other Definitions in Industry ............................................................................................................................................... 8
Common Application of SPS in Industry .............................................................................................................................. 8
Classification of SPS Types ................................................................................................................................................... 9
Common Exclusions from the SPS Definition in Industry .................................................................................................. 10
Exclusion for Operator Aides ............................................................................................................................................. 11
Voltage Threshold .............................................................................................................................................................. 11
Proposed Definition ............................................................................................................................................................... 11
Definition of Significant and Limited Impact ......................................................................................................................... 13
Chapter 2 – Design and Maintenance Requirements ................................................................................................................ 14
General Design Considerations .............................................................................................................................................. 14
SPS Single Component Failure Requirements........................................................................................................................ 14
Maintenance and Testing ...................................................................................................................................................... 15
Chapter 3 – Study and Documentation Requirements .............................................................................................................. 16
Review and Approval of New or Modified SPS ...................................................................................................................... 16
Assessment of Existing SPS .................................................................................................................................................... 17
Study of SPS in Annual Transmission Planning Assessments ............................................................................................. 17
Periodic Comprehensive Assessments of SPS Coordination .............................................................................................. 17
Documentation Requirements .............................................................................................................................................. 18
Data Submittals by Entities that Own SPS ......................................................................................................................... 18
SPS Database ..................................................................................................................................................................... 19
Chapter 4 – Operational Requirements ..................................................................................................................................... 20
Monitoring of Status .............................................................................................................................................................. 20
Notification of Status ............................................................................................................................................................. 20
Response to Failures .............................................................................................................................................................. 21
Operational Documentation .................................................................................................................................................. 21
Chapter 5 – Analysis of SPS Operations ..................................................................................................................................... 22
SPS Misoperation Definition .................................................................................................................................................. 22
SPS Operation Review Process .............................................................................................................................................. 23
Chapter 6 – Recommendations ................................................................................................................................................. 25
Definition ............................................................................................................................................................................... 25
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
3 of 48
Classification .......................................................................................................................................................................... 26
Applicability to Functional Model Entities ............................................................................................................................. 26
Revisions to Reliability Standards .......................................................................................................................................... 26
Standard PRC-012-1 – SPS Review, Assessment, and Documentation .............................................................................. 28
Standard PRC-016-1 – SPS Misoperations ......................................................................................................................... 28
Standard PRC-005-2 – Protection System Maintenance and Testing ................................................................................ 28
Recommendations to Be Included in Other Standards ..................................................................................................... 28
Appendix A – Modeling and Simulation Considerations ........................................................................................................... 29
General Considerations for Simulations ................................................................................................................................ 29
Use of SPS Simulations in Transmission Planning Studies ..................................................................................................... 31
Appendix B – Operational Considerations ................................................................................................................................. 33
Real-time SPS Evaluation ....................................................................................................................................................... 33
Multiple Decision-Making Capability ..................................................................................................................................... 33
Information Management ..................................................................................................................................................... 33
Modeling Simplicity and Usability.......................................................................................................................................... 34
Appendix C – Mapping of Requirements from Existing Standards ............................................................................................ 35
Appendix D – Standards Committee Request for Research; January 9, 2011 ........................................................................... 43
Appendix E – Scope of Work Approved by the Planning Committee; June 8, 2011 .................................................................. 44
Appendix F – System Analysis and Modeling Subcommittee Roster ......................................................................................... 45
Appendix G – System Protection and Control Subcommittee Roster ....................................................................................... 46
Appendix H – Additional Contributors ....................................................................................................................................... 47
Appendix I – Revision History .................................................................................................................................................... 48
This technical document was approved by the NERC Planning Committee on March 5, 2013.
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
4 of 48
Executive Summary
The existing NERC Glossary of Terms definition for a Special Protection System (SPS or, as used in the Western
Interconnection, a Remedial Action Scheme or RAS) lacks clarity and specificity necessary for consistent identification and
classification of protection schemes as SPS or RAS across the eight NERC Regions, leading to inconsistent application of the
related NERC Reliability Standards. In addition, three of the related standards (PRC-012-0, PRC-013-0, and PRC-014-0) were
identified by FERC in Order No. 693 as fill-in-the-blank standards and consequently are not mandatory and enforceable.
NERC Standards Project 2010-05.2, Phase 2 of Protection Systems: SPS and RAS, will modify the current standards and
definitions related to SPS and RAS. The NERC Standards Committee has identified that prior to initiating a project to address
these issues, additional research is necessary to clearly define the problem and recommend solutions for consideration. A
request for research was submitted by the Standards Committee on January 9, 2012 (see Appendix D). The Planning
Committee had already approved a joint effort by the System Analysis and Modeling Subcommittee (SAMS) and System
2
Protection and Control Subcommittee (SPCS) on June 8, 2011 (see Appendix E) which includes issues identified in the
request for research. This report addresses all issues identified in the scope of the joint SAMS and SPCS project as well as
the Standards Committee request for research; upon approval by the Planning Committee the report should be forwarded
to the Standards Committee to support Project 2010-05.2.
This report includes recommendations for a new definition of SPS and revisions to the six SPS-related PRC standards. A
strawman definition is provided that eliminates ambiguity in the existing definition and identifies 13 types of schemes that
are not SPS, but for which uncertainty has existed in the past based on experience within the Regions. The report also
recommends that SPS should be classified based on the type of event to which the SPS responds and the consequence of
misoperation. Classification of SPS facilitates standard requirements commensurate with potential reliability risk. Four
classifications are proposed.
This report provides recommendations to address FERC concerns with PRC-012-0, PRC-013-0, and PRC-014-0, which assign
requirements to Regional Reliability Organizations. Recommendations are made to reassign requirements to specific users,
owners, and operators of the bulk power system to remedy this situation.
Project 2010-05.2 should consolidate the requirements pertaining to review, assessment, and documentation of SPS into
one standard that includes continent-wide procedures for reviewing new or modified SPS, for assessing existing SPS in
annual transmission planning assessments, and for periodic comprehensive SPS assessments. The project also should revise
requirements pertaining to analysis and reporting of SPS misoperations in a revision of standard PRC-016-0.1. Due to the
significant difference between protection systems and SPS, the subject of SPS misoperations should not be included in a
future revision of PRC-004. Given the scope of work and need for drafting team members with different subject matter
expertise it may be appropriate to sub-divide Project 2010-05.2 to address review, assessment and documentation of SPS
separately from analysis and reporting of misoperations. This report also provides recommendations for Standards
Committee consideration that are outside the scope of Project 2010-05.2. These additional recommendations pertain to
maintenance and testing and operational aspects of SPS.
2
The original scope of work involved the SPCS and the predecessor of SAMS, the Transmission Issues Subcommittee (TIS).
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Introduction
Problem Statement
The existing NERC Glossary of Terms definition for a Special Protection System (SPS or, as used in the Western
Interconnection, a Remedial Action Scheme or RAS) lacks clarity and specificity necessary for consistent identification and
classification of protection schemes as SPS or RAS across the eight NERC Regions, leading to inconsistent application of the
related NERC Reliability Standards. In addition, three of the related standards (PRC-012-0, PRC-013-0, and PRC-014-0) were
identified by FERC in Order No. 693 as fill-in-the-blank standards and consequently are not mandatory and enforceable.
NERC Standards Project 2010-05.2, Phase 2 of Protection Systems: SPS and RAS, will modify the current standards and
definitions related to SPS and RAS. The NERC Standards Committee has identified that prior to initiating a project to address
these issues, additional research is necessary to clearly define the problem and recommend solutions for consideration.
Background
NERC Definitions
The existing NERC Glossary of Terms defines an SPS and RAS as:
Special Protection System (Remedial Action Scheme)
An automatic protection system designed to detect abnormal or predetermined system conditions, and take corrective
actions other than and/or in addition to the isolation of faulted components to maintain system reliability. Such action
may include changes in demand, generation (MW and Mvar), or system configuration to maintain system stability,
acceptable voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load shedding or (b)
fault conditions that must be isolated or (c) out-of-step relaying (not designed as an integral part of an SPS). Also called
Remedial Action Scheme.
In this document, use of the term SPS in general discussions and proposals for future definitions and standards apply to
both SPS and RAS. Specific references to existing practices within Regions use the term SPS or RAS as appropriate for that
Region.
The NERC Glossary of Terms defines a Protection System as:
Protection System
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including batteries, battery chargers, and non-batterybased dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices.
Inclusion of the words “protection system” in the term Special Protection System has raised questions whether this is an
intentional reference such that SPS are a subset of Protection Systems. Use of protection system (lower case) within the SPS
definition identifies that SPS are not Protection Systems. While SPS may include the same types of components as
Protection Systems, SPS are not limited to detecting faults or abnormal conditions and tripping affected equipment. SPS
may, for example, effect a change to the operating state of power system elements to preserve system stability or to avoid
unacceptable voltages or overloads in response to system events. There are many reasons for implementing an SPS; for
example, an SPS can be implemented to ensure compliance with the TPL Reliability Standards, to mitigate temporary
operating conditions or abnormal configurations (e.g., during construction or maintenance activities), or in instances where
system operators would not be able to respond quickly enough to avoid adverse system conditions.
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Introduction
A second area in which the existing SPS definition lacks clarity is the actions that are characteristics of SPS. The actions listed
in the definition are broad and may unintentionally include equipment whose purpose is not expressly related to preserving
system reliability in response to an event. Inclusion of any system taking “corrective action other than … isolation of faulted
components to maintain system reliability” could be deemed to include equipment such as voltage regulators and switching
controls for shunt reactive devices. This inclusion would then make these elements subject to single component failure
considerations (sometimes referred to as redundancy considerations), coordination, reporting, and maintenance and
testing requirements that may be required in the NERC Reliability Standards related to SPS.
This report proposes a revised definition of SPS to address these issues. Development of the proposed definition considered
other definitions, common applications, and existing practices regarding classification of SPS.
NERC Reliability Standards
The NERC Reliability Standards contain six standards in the protection and control (PRC) series that specifically pertain to
SPS.
•
PRC-012-0: Special Protection System Review Procedure
•
PRC-013-0: Special Protection System Database
•
PRC-014-0: Special Protection System Assessment
•
PRC-015-0: Special Protection System Data and Documentation
•
PRC-016-0.1: Special Protection System Misoperations
•
PRC-017-0: Special Protection System Maintenance and Testing
Three of these standards are not mandatory and enforceable because FERC identified them as fill-in-the-blank standards in
Order No. 693, Mandatory Reliability Standards for the Bulk-Power System. These standards assign the Regional Reliability
Organizations responsibility to establish regional procedures and databases, and to assess and document the operation,
coordination, and compliance of SPS. The deference to regional practices, coupled with lack of clarity in the definition of
SPS, preclude consistent application of requirements pertaining to SPS. This report provides recommendations that may be
implemented through the NERC Reliability Standards Development Process to consolidate the standards and provide
greater consistency and clarity regarding requirements.
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Chapter 1 – SPS Definition
Considerations for a Revised Definition
Other Definitions in Industry
3
Several IEEE papers define a similar term to SPS: System Integrity Protection System (SIPS). Adopting the SIPS definition is
not appropriate because it is more inclusive than NERC’s definition:
“The SIPS encompasses special protection system (SPS), remedial action schemes (RAS), as well as other system
4
integrity schemes, such as underfrequency (UF), undervoltage (UV), out-of-step (OOS), etc.”
NERC applies special consideration to UF and UV load shedding schemes in the Reliability Standards and considers OOS
relaying in the context of traditional protection systems. Thus, SIPS is not an appropriate term for use in the Reliability
Standards, and a new definition of SPS is more appropriate.
Common Application of SPS in Industry
Most SPS are used to address a range of system issues including stability, voltage, and loading concerns. Less common
applications include arresting sub-synchronous resonance and suppressing torsional oscillations. Actions taken by SPS may
include (but are not limited to): system reconfiguration, generation rejection or runback, load rejection or shedding,
reactive power or braking resistor insertion, and runback or fast ramping of HVdc.
SPS are often deployed because the operational solutions they facilitate are substantially quicker and less expensive to
implement than construction of transmission infrastructure. Permanent SPS have been implemented in some cases where
the cost associated with system expansion is prohibitive, construction is not possible due to physical constraints, or
obtaining permits is not feasible. In other cases temporary SPS have been implemented to maintain system reliability until
transmission infrastructure is constructed; or when a reliability risk is temporary (e.g., during equipment outages) and the
expense associated with permanent transmission upgrades is not justified.
The deployment of SPS adds complexity to power system operation and planning:
“Although SPS deployment usually represents a less costly alternative than building new infrastructure, it carries
with it unique operational elements among which are: (1) risks of failure on demand and of inadvertent activation;
(2) risk of interacting with other SPS in unintended ways; (3) increased management, maintenance, coordination
5
requirements, and analysis complexity.”
Subsequent sections of this report consider these three operational elements and provide recommendations regarding how
they should be addressed in the NERC Reliability Standards. A summary of the number of schemes identified as SPS or RAS
by Region is provided below.
Table 1: Overview of SPS by Region 6
Region
Total Number
Region
Total Number
FRCC
20
SERC
20
MRO
36
SPP
6
NPCC
117
TRE
24
RFC
47
WECC
192
3
One noteable reference, Madani, et al, “IEEE PSRC Report on Global Industry Experiences with System Integrity Protection
Schemes (SIPS),” IEEE Trans. on Power Delivery, Vol. 25, Oct. 2010.
4
Ibid.
5
McCalley, et al, “System Protection Schemes: Limitations, Risks, and Management”, PSERC Publication 10-19, Dec 2010.
6
Numbers for 2011 obtained from data reported in the NERC Reliability Metric ALR6-1.
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Chapter 1 – SPS Definition
Classification of SPS Types
Three regions classify SPS according to various criteria, including the type of event the SPS is designed to address as well as
the ability of the SPS to impact on a local versus wide-area reliability. The following information describes how NPCC, WECC
and TRE classify SPS. Please note that examples of regional practices are provided for illustration throughout this document,
but are not necessarily best practices or applicable to all Regions. Also in this context, what constitutes local versus widearea varies among Regions and is not based on the NERC glossary term Wide Area, which is specific to calculation of
7
Interconnection Reliability Operating Limits (IROL).
NPCC
Type I – A Special Protection System which recognizes or anticipates abnormal system conditions resulting from design
and operating criteria contingencies, and whose misoperation or failure to operate would have a significant adverse
impact outside of the local area. The corrective action taken by the Special Protection System along with the actions
taken by other protection systems are intended to return power system parameters to a stable and recoverable state.
Type II – A Special Protection System which recognizes or anticipates abnormal system conditions resulting from
extreme contingencies or other extreme causes, and whose misoperation or failure to operate would have a significant
adverse impact outside of the local area.
Type III – A Special Protection System whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for their classification:
Significant adverse impact – With due regard for the maximum operating capability of the affected systems, one or
more of the following conditions arising from faults or disturbances, shall be deemed as having significant adverse
impact:
a.
system instability;
b.
unacceptable system dynamic response or equipment tripping;
c.
voltage levels in violation of applicable emergency limits;
d.
loadings on transmission facilities in violation of applicable emergency limits;
e.
unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and number of system
elements contained will vary based on system characteristics. A local area may be relatively large geographically with
relatively few buses in a sparse system, or be relatively small geographically with a relatively large number of buses in a
densely networked system.
W ECC
Local Area Protection Scheme (LAPS): A Remedial Action Scheme (RAS) whose failure to operate would NOT result in
any of the following:
•
Violations of TPL-(001 thru 004)-WECC-1-CR – System Performance Criteria,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
7
The NERC Glossary defines Wide Area as “The entire Reliability Coordinator Area as well as the critical flow and status
information from adjacent Reliability Coordinator Areas as determined by detailed system studies to allow the calculation
of Interconnected Reliability Operating Limits.”
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Chapter 1 – SPS Definition
Wide Area Protection Scheme (WAPS): A Remedial Action Scheme (RAS) whose failure to operate WOULD result in any
of the following:
•
Violations of TPL-(001 thru 004)-WECC-1-CR – System Performance Criteria,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
Safety Net: A type of Remedial Action Scheme designed to remediate TPL-004-0 (System Performance Following
Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D)), or other extreme
events.
TR E:
(a) A “Type 1 SPS” is any SPS that has wide-area impact and specifically includes any SPS that:
(i) Is designed to alter generation output or otherwise constrain generation or imports over DC Ties; or
(ii) Is designed to open 345 kV transmission lines or other lines that interconnect Transmission Service Providers
(TSPs) and impact transfer limits.
(b) A “Type 2 SPS” is any SPS that has only local-area impact and involves only the facilities of the owner-TSP.
These three regional classifications can be roughly mapped:
•
NPCC Type I = WECC WAPS = TRE Type 1
•
NPCC Type III = WECC LAPS = TRE Type 2
•
NPCC Type II = WECC Safety Net
SPS classification differentiates the reliability risk associated with SPS and provides a means to establish more or less
stringent requirements consistent with the reliability risk. For example, it may be appropriate to establish less stringent
requirements pertaining to monitoring or single component failure of SPS that present a lower reliability risk. A
recommendation for classification of SPS is included with the proposed definition and subsequent discussion of standard
requirements includes recommendations where different requirements based on classification are deemed appropriate.
Common Exclusions from the SPS Definition in Industry
Exclusions provide a means to assure that specific protection or control systems are not unintentionally included as SPS.
The NERC glossary definition of SPS states that “An SPS does not include (a) underfrequency or undervoltage load shedding
or (b) fault conditions that must be isolated or (c) out-of-step relaying (not designed as an integral part of an SPS).”
Even with the exclusions in the NERC definition, other commonly applied protection and control systems meet the general
language in the SPS definition. Considerable effort has been expended by industry discussing what systems are SPS. NPCC
and SERC have documented examples of exclusions to the SPS definition in their regional guidelines. NPCC explicitly
excludes “Automatic underfrequency load shedding; Automatic undervoltage load shedding and manual or automatic
8
locally controlled shunt devices.” SERC’s SPS guideline calls out specific exclusions as follows:
8
a.
UFLS and/or UVLS,
b.
Fault conditions that must be isolated including bus breakup / backup / breaker failure
protection,
c.
Relays that protect for specific equipment damage (such as overload, overcurrent, hotspot,
reclose blocking, etc.),
d.
Out of step relaying,
e.
Capacitor bank / reactor controls,
NPCC Glossary of Terms Used by Directories
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Chapter 1 – SPS Definition
f.
Load Tap Changer (LTC) controls,
g.
Automated actions that could be performed by an operator in a reasonable amount of time,
including alternate source schemes, and
h.
Scheme that trips generation to prevent islanding
A recommended list of protection and control systems that should be excluded from classification as SPS is included with
the proposed definition.
Exclusion for Operator Aides
SAMS and SPCS considered a number of factors in discussing this subject including:
1) whether the actions are required to be completed with such urgency that it would be difficult for an operator to
react and execute in the necessary time, and
2) whether the required actions are of such complexity or across such a large area that it would be difficult for an
operator to perform the actions in the necessary time.
It is difficult to address these questions with concise and measurable terms, making it difficult to explicitly exclude them in
the definition without introducing ambiguous terms counter to the objective of providing needed clarity in the SPS
definition. Whether its existence is based upon convenience or not, any automated system with the potential to impact
bulk power system reliability should be defined and expressed to the appropriate authority (e.g., Planning Coordinator,
Reliability Coordinator) for the purposes of system modeling and coordination studies, to ensure that these systems are
properly coordinated with other protection and control systems, and to ensure that inadvertent operations do not result in
adverse system impacts.
On these bases, SAMS and SPCS decided not to provide an exclusion for schemes based on a general criterion as to whether
the scheme automates actions that an operator could perform in a reasonable amount of time or schemes installed for
operator convenience. However, SAMS and SPCS do recommend exclusions for specific applications that meet these criteria
such as automatic sequences that are initiated manually by an operator. Furthermore, any scheme that is not installed “to
meet system performance requirements identified in the NERC Reliability Standards, or to limit the impact of two or more
elements removed, an extreme event, or Cascading” would be excluded by definition, regardless of whether it is installed to
assist an operator.
Voltage Threshold
All elements, at any voltage level, of an SPS intended to remediate performance issues on the bulk electric system (BES), or
of an SPS that acts upon BES elements, should be subject to the NERC requirements.
Proposed Definition
The proposed definition clarifies the areas that have been interpreted differently between individual entities and within
Regions, in some cases leading to differing regional definitions of SPS. The proposed definition provides a framework for
differentiating among SPS with differing levels of reliability risk and will support the drafting of new or revised SPS
standards.
Special Protection System (SPS)
A scheme designed to detect predetermined system conditions and automatically take corrective actions,
other than the isolation of faulted elements, to meet system performance requirements identified in the
NERC Reliability Standards, or to limit the impact of: two or more elements removed, an extreme event,
or Cascading.
Subject to the exclusions below, such schemes are designed to maintain system stability, acceptable
system voltages, acceptable power flows, or to address other reliability concerns. They may execute
actions that include but are not limited to: changes in MW and Mvar output, tripping of generators and
other sources, load curtailment or tripping, or system reconfiguration.
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Chapter 1 – SPS Definition
The following schemes do not constitute an SPS in and of themselves:
a)
Underfrequency or undervoltage load shedding
b) Locally sensing devices applied on an element to protect it against equipment damage for nonfault conditions by tripping or modifying the operation of that element, such as, but not limited
to, generator loss-of-field or transformer top-oil temperature
c)
Autoreclosing schemes
d) Locally sensed and locally operated series and shunt reactive devices, FACTS devices, phaseshifting transformers, variable frequency transformers, generation excitation systems, and tapchanging transformers
e)
Schemes that prevent high line voltage by automatically switching the affected line
f)
Schemes that automatically de-energize a line for non-fault operation when one end of the line is
open
g)
Out-of-step relaying
h) Schemes that provide anti-islanding protection (e.g., protect load from effects of being isolated
with generation that may not be capable of maintaining acceptable frequency and voltage)
i)
Protection schemes that operate local breakers other than those on the faulted circuit to
facilitate fault clearing, such as, but not limited to, opening a circuit breaker to remove infeed so
protection at a remote terminal can detect a fault or to reduce fault duty
j)
Automatic sequences that proceed when manually initiated solely by an operator
k)
Sub-synchronous resonance (SSR) protection schemes
l)
Modulation of HVdc or SVC via supplementary controls such as angle damping or frequency
damping applied to damp local or inter-area oscillations
m) A Protection System that includes multiple elements within its zone of protection, or that isolates
more than the faulted element because an interrupting device is not provided between the
faulted element and one or more other elements
SPS are categorized into four distinct types. These types may be subject to different requirements within
the NERC Reliability Standards.
•
Type PS (planning-significant): A scheme designed to meet system performance requirements
identified in the NERC Reliability Standards, where failure or inadvertent operation of the
scheme can have a significant impact on the BES.
•
Type PL (planning-limited): A scheme designed to meet system performance requirements
identified in the NERC Reliability Standards, where failure or inadvertent operation of the
scheme can have only a limited impact on the BES.
•
Type ES (extreme-significant): A scheme designed to limit the impact of two or more elements
removed, an extreme event, or Cascading, where failure or inadvertent operation of the scheme
can have a significant impact on the BES.
•
Type EL (extreme-limited): A scheme designed to limit the impact of two or more elements
removed, an extreme event, or Cascading, where failure or inadvertent operation of the scheme
can have only a limited impact on the BES.
An SPS is classified as having a significant impact on the BES if failure or inadvertent operation of the
scheme results in any of the following:
•
Non-Consequential Load Loss ≥ 300 MW
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Chapter 1 – SPS Definition
•
Aggregate resource loss (tripping or runback of generation or HVdc) > the largest Real Power
9
resource within the interconnection
•
Loss of synchronism between two or more portions of the system each including more than one
generating plant
•
Negatively damped oscillations
If none of these criteria are met, the SPS is classified as having a limited impact on the BES.
Definition of Significant and Limited Impact
The parameters used to define the bright line between “significant” and “limited” impacts are proposed to consider only
the electrical scale of the event. Defining the bright line in this way eliminates the difficulty in distinguishing the geographic
impact of an SPS as either “wide” or “local.”
NERC Standard EOP-004-1, DOE Form OE-417 Electric Emergency Incident and Disturbance Report, establishes the criteria
by which an event is categorized as a Disturbance and requires a disturbance report. In terms of SPS, the proposed criteria
for significant impact mirrors EOP-004-1 by including a non-consequential load loss value of 300 MW.
NERC Reliability Standards require consideration of loss of any generating unit; therefore, generating unit loss would not
impact reliability of the bulk power system unless the combined capacity loss exceeds the largest unit within the
interconnection. The generation loss level was selected as a loss greater than the largest unit within an interconnection on
this basis.
Tripping multiple generating units exceeding the capacity of the largest unit within an interconnection, system separation
(loss of synchronism) that results in isolation of a portion of an interconnection, or system oscillations that increase in
magnitude (negatively-damped) are indicators of adverse impact to the reliability of an interconnection. These criteria
identify system performance indicative of the potential for instability, uncontrolled separation, or cascading outages,
without requiring detailed analyses to confirm the extent to which instability, uncontrolled separation, or cascading outages
may occur. These indicators, combined with the loss of load criterion, are proposed to identify the potential reliability risk
associated with failure of a SPS. Subsequent sections of this report recommend requirements for assessment and design of
SPS based on whether the potential reliability risk associated with the SPS are significant versus limited impacts.
The proposed thresholds differentiate between significant and limited impact. While it should be clear there is no upper
threshold on what constitutes a significant impact, there also is no lower threshold proposed as to what constitutes limited
impact. Whether a scheme is an SPS is determined by the definition; significant and limited impact are used only to classify
SPS. For example, if a scheme is installed to meet system performance requirements identified in the NERC Reliability
Standards then it is an SPS regardless of its potential impact. A failure of the SPS would result in a violation of a NERC
Reliability Standard. Thus, excluding a scheme with impact below a certain threshold would undermine the reliability
objective of the standard requirement the scheme is installed to address.
9
I.e., Eastern, Western, ERCOT, or Quebec Interconnection.
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Chapter 2 – Design and Maintenance Requirements
Under the proposed definition, SPS are implemented to preserve acceptable system performance, and as such may be
critical to power system reliability and therefore subject to single component failure considerations, and maintenance and
testing requirements outlined in the PRC standards.
General Design Considerations
Aside from the single component failure, and maintenance and testing considerations outlined below, Disturbance
Monitoring Equipment should be provided in the design of an SPS to permit analysis of the SPS performance following an
event. Also, as with other automated systems, the design of an SPS should facilitate its maintenance and testing.
SPS Single Component Failure Requirements
Requirement R1.3 in PRC-012-0 requires SPS owners to demonstrate an SPS is designed so that a single SPS component
failure, when the SPS was intended to operate, does not prevent the interconnected transmission system from meeting the
performance requirements defined in NERC Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0. This requirement
should be retained in future standards such that Types PS and PL SPS are required to be designed so that power system
performance meets the performance requirements of TPL-001-0, TPL-002-0, or TPL-003-0, in the event of a single
component failure. The design of Type PS and PL SPS can provide the required performance through any of the methods
outlined below, or a combination of these methods:
1.
Arming more load or generation than necessary to meet the intended results. Thus the failure of the scheme to
drop a portion of load or generation would not be an issue. In this context it is necessary to arm the tripping of
more load delivery points or generating units rather than simply arming more MW of load or generation. When
this option is used, studies of the SPS design must demonstrate that tripping the total armed amount of load or
generation will not cause other adverse impacts to reliability.
2.
Providing redundancy of SPS components listed below.
•
Any single ac current source and/or related input to the SPS. Separate secondary windings of a free-standing
current transformer (CT) or multiple CTs on a common bushing should be considered an acceptable level of
redundancy.
•
Any single ac voltage source and/or related input to the SPS. Separate secondary windings of a common
capacitance coupled voltage transformer (CCVT), voltage transformer (VT), or similar device should be
considered an acceptable level of redundancy.
•
Any single device used to measure electrical quantities used by the SPS.
•
Any single communication channel and/or any single piece of related communication equipment used by the
SPS.
•
Any single computer or programmable logic device used to analyze information and provide SPS operational
output.
•
Any single element of the dc control circuitry that is used for the SPS, including breaker closing circuits.
•
Any single auxiliary relay or auxiliary device used by the SPS.
•
Any single breaker trip coil for any breaker operated by the SPS.
•
Any single station battery or single charger, or other single dc source, where central monitoring is not
provided for both low voltage and battery open conditions.
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Chapter 2 – Design and Maintenance Requirements
10
3.
Using remote or time delayed actions such as breaker failure protection or alternative automatic actions to back
up failures of single components (e.g., an independent scheme that trips an element if an overload exists for
longer than the time necessary for the SPS to take action). The backup operation would still need to provide
mitigation to meet the necessary result in the required timeframe.
4.
For Type PL SPS, manual backup operation may be used to address the failure of a single SPS component if studies
are provided to show that implemented procedures will be effective in providing the required response when a
SPS failure occurs. The implemented procedures will include alarm response and manual operation time
requirements to provide the backup functions.
Some SPS utilize an Energy Management System (EMS) system for transmitting signals or calculating information necessary
for SPS operation such as the amount of load or generation to trip. Loss of the EMS system must be considered when
assessing the impact of a single component failure. For example, when the EMS is used to transmit a signal, a separate
communication path must be available. When a non-redundant EMS provides a calculated value to two otherwise
independent systems, a backup calculation or default value must be provided to the SPS in the event of an EMS failure.
Types ES and EL SPS are designed to provide system protection against extreme events. The events that Types ES and EL SPS
are intended to address have a lower probability of occurrence and the TPL standards do not require mitigation for these
events. Dependability of SPS operation is therefore not critical for these events and, consistent with the existing standards,
these SPS should not be required to perform their protection functions even with a single component failure. Design
requirements for Type ES SPS should emphasize security; however, in some cases Type ES SPS are installed to address an
event with consequences so significant (e.g., system separation or collapse of an interconnection) that consideration should
be given to both dependability and security. In consideration that the addition of redundancy in some cases might make the
11
SPS less secure, such cases may warrant implementation of a voting scheme .
Maintenance and Testing
The Project 2007-17, Protection System Maintenance and Testing, drafting team revised PRC-005 to include maintenance
12
and testing requirements for SPS contained in PRC-017-0. All of the existing requirements in PRC-017-0 that are based on
a reliability objective are mapped to PRC-005-2. However, this report identifies two subjects that are not covered in either
the existing standard or the proposed standard:
•
Complex SPS require different procedures than those used for maintenance of protection systems.
•
Maintenance of non-protection system components used in SPS is not addressed in any existing NERC Reliability
Standards.
These subjects should be addressed in a future revision of PRC-005 or development of a separate standard.
10
In this context it is not intended that breaker failure protection must be redundant; rather, that breaker failure protection
may be relied on to meet the design requirements (e.g., if an SPS required tripping a breaker with a single trip coil).
11
A voting scheme achieves both dependable and secure operation by requiring, for example, two out of three schemes to
detect the condition prior to initiating action.
12
PRC-005-2 was adopted by the NERC Board of Trustees on November 7, 2012
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Chapter 3 – Study and Documentation Requirements
Review and Approval of New or Modified SPS
Requirement R1 in PRC-012-0 requires each Regional Reliability Organization to have a documented review procedure to
ensure that SPS comply with regional criteria and NERC Reliability Standards. However, the potential for SPS interaction and
for SPS operation or misoperation to have inter-regional impacts suggests that a uniform procedure for reviewing SPS is
important to ensure bulk power system reliability. This report recommends fundamental aspects that should be included in
a continent-wide SPS review procedure and included in the revised reliability standards pertaining to SPS. The review
process should be conducted by an entity or entities with the widest possible view of system reliability, and must be a user,
owner, or operator of the bulk power system. To assure that both planning and operating views are evaluated before a new
or modified SPS is placed in service, responsibility for reviewing and approving implementation of SPS should be assigned to
the Reliability Coordinator and Planning Coordinator. Ideally these reviews should be performed on a regional or
interconnection-wide basis. If in the future an entity is registered as the Reliability Assurer for each Region, the
responsibility for performing these reviews, or alternately for coordinating these reviews, should be assigned to the
Reliability Assurer.
A continent-wide review process should be established in a revised reliability standard that includes the following aspects:
13
•
The SPS owner should be required to obtain approval from its Reliability Coordinator and its Planning
14
Coordinator in whose area the SPS is installed prior to placing a new or modified SPS in service.
•
An entity proposing a new or modified SPS should be required to file an application with its Reliability Coordinator
and Planning Coordinator that includes the following information:
o
A document outlining the details of the SPS as specified below in the section titled, Data Submittals by Entities
that Own SPS.
o
Studies that demonstrate the operation, coordination, and effectiveness of the SPS, including the impacts of
correct operation, a failure to operate, and inadvertent operation. The study report should include the
15
following:
Entity conducting the SPS study
Study completion date
Study years
System conditions
Contingencies analyzed
Demonstration that the SPS meets criteria discussed in the Design Considerations chapter of this report
Discussion of coordination of the SPS with other SPS, UFLS, UVLS, and protection systems
•
The Reliability Coordinator and Planning Coordinator should be required to provide copies of the application and
supporting information to Transmission Planners, Transmission Operators, and Balancing Authorities within their
area, and to adjacent Reliability Coordinators and Planning Coordinators.
•
Entities receiving the application should be allowed to provide comments to the Reliability Coordinator and
Planning Coordinator.
13
In cases where more than one entity owns an SPS, the standards should designate that a designated “reporting entity” be
responsible for transmitting data to the Reliability Coordinator and Planning Coordinator, while all owners retain
responsibility for other requirements such as maintenance and testing.
14
In cases where an SPS has components installed in or takes action in more than one Reliability Coordinator area or
Planning Coordinator area, all affected Reliability Coordinators and Planning Coordinators should have approval authority.
15
The same documentation requirements should apply to Periodic Comprehensive Assessments of SPS Coordination.
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Chapter 3 – Study and Documentation Requirements
•
When deciding whether to approve an SPS, the Reliability Coordinator and the Planning Coordinator in whose area
the SPS is to be installed or modified should be required to consider supporting information provided with the
application; comments from Transmission Planners, Transmission Operators, and Balancing Authorities and other
Reliability Coordinators and Planning Coordinators; and any supplemental information provided by the SPS owner.
•
The basis of the Reliability Coordinator and Planning Coordinator approval should be limited to whether all
required information has been submitted and the studies are sufficient to support that all performance
requirements are met.
Assessment of Existing SPS
Study of SPS in Annual Transmission Planning Assessments
Requirement R1 in PRC-014-0 specifically addresses assessment of the operation, coordination, and effectiveness of all SPS
and assigns this responsibility to the Regional Reliability Organization. Reliability standards must assign responsibility to
owners, operators, and users of the bulk power system. For assessments of SPS, it is important to identify an entity with the
necessary expertise in system studies and a wide-area view to facilitate coordination of SPS across the system. Instead of
assigning this responsibility to the Regional Reliability Organization or the Regional Entity, the assessment responsibility
should be assigned to the Planning Coordinator and Transmission Planner for SPS within their specific area.
Annually, the Planning Coordinator and Transmission Planner should review the operation, coordination, and effectiveness
of the SPS, including the impacts of correct operation, a failure to operate, and inadvertent operation. If system changes
have occurred which can affect the operation of the SPS, annual studies should include system conditions and
contingencies modeled in the study supporting the application for installation of or modifications to an SPS.
Any issues identified should be documented and submitted to the Reliability Coordinator and the SPS owner. The Reliability
Coordinator and Planning Coordinator should be required to determine, in consultation with the SPS owner, whether a
corrective action plan is required, and if so, whether the SPS can remain in-service or must be removed from service until a
corrective action plan is implemented. If a corrective action plan is required, the SPS owner should be required to submit an
application for a modified SPS as described above in the section titled Review and Approval of New or Modified SPS.
Periodic Comprehensive Assessments of SPS Coordination
Comprehensive assessment should occur every five years, or sooner, if significant changes are made to system topology or
operating characteristics that may impact the coordination among SPS and between SPS and UFLS, UVLS, and other
protection systems. Responsibility for the comprehensive assessment should be assigned to the Reliability Coordinator to
achieve the wide-area review necessary for a comprehensive assessment. Planning Coordinators, Transmission Planners,
Transmission Operators, Balancing Authorities, and adjacent Reliability Coordinators should be required to provide support
to the Reliability Coordinator when requested to do so. As part of the periodic review the Reliability Coordinator should be
required to request the Planning Coordinator and Transmission Planner to assess and document whether the SPS is still
necessary, serves its intended purpose, meets criteria discussed in the Design Considerations chapter of this report,
coordinates with other SPS, UFLS, UVLS, and protection systems, and does not have unintended adverse consequences on
reliability.
The Reliability Coordinator should be required to provide its periodic assessment to Planning Coordinators, Transmission
Planners, Transmission Operators, and Balancing Authorities in its area, and to adjacent Reliability Coordinators, and should
be required to consider comments provided by these entities. Any issues identified with an SPS should be documented and
submitted to the SPS owner. If any concerns are identified, the Reliability Coordinator and the Planning Coordinator in
whose area the SPS is installed should determine, in consultation with the SPS owner, whether a corrective action plan is
required, and if so, whether the SPS can remain in-service or must be removed from service until a corrective action plan is
implemented. If a corrective action plan is required, the SPS owner should be required to submit an application for a
modified SPS as described above in the section titled Review and Approval of New or Modified SPS.
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Chapter 3 – Study and Documentation Requirements
Documentation Requirements
Data Submittals by Entities that Own SPS
Reliability standard PRC-015-0 establishes requirements for SPS owners to provide data for existing and proposed SPS as
specified in reliability standard PRC-013-0 Requirement R1. PRC-013-0 establishes the data provided shall include the
following:
•
Design Objectives — Contingencies and system conditions for which the SPS was designed
•
Operation — The actions taken by the SPS in response to Disturbance conditions
•
Modeling — Information on detection logic or relay settings that control operation of the SPS
This requirement should be carried forward to the revised standards for the SPS owner to provide detailed information
regarding the conditions of SPS operation. However, this requirement should be modified to ensure that communication of
this information is clear and understandable to all entities that require the information to plan and operate the bulk power
system (e.g., Planning Coordinators, Transmission Planners, Reliability Coordinators, Transmission Operators, and Balancing
Authorities). Additional specificity should be added to this list of data to assure that sufficient information is provided for
entities to understand and model SPS operation.
Since SPS design and complexity vary considerably, a brief description of the action taken when certain system conditions
are detected generally does not provide a sufficient level of detail. Conversely, logic and control wiring diagrams may
provide too much detail that is not readily understood except by the SPS owner’s protection and control engineers. To
achieve an appropriate level of detail that provides a common understanding by the SPS owner and other entities, the SPS
owner should work with the Transmission Planner to develop a document outlining the details of the SPS operation
specifically tailored to the needs and knowledge level of the entities that require this information to plan and operate the
bulk power system. The document should include the following:
•
SPS name
•
SPS owner
•
Expected in-service date
•
Whether the SPS is intended to be permanent or temporary
•
SPS classification (per revised definition), and documentation or explanation of how the SPS mitigates the planning
or extreme event and why the impact is significant or limited
•
Logic diagram, flow chart, or truth table documenting the scheme logic and illustrating how functional operation is
accomplished
•
Whether the SPS logic is:
•
16
o
Event-based
o
Parameter-based
o
A combination of event-based and parameter-based
17
System performance criteria violation necessitating the SPS (e.g., thermal overload, angular instability, poor
oscillation damping, voltage instability, under-/over-voltage, slow voltage recovery)
16
Event-based schemes directly detect outages and/or fault events and initiate actions such as generator/load tripping to
fully or partially mitigate the event impact. This open-loop type of control is commonly used for preventing system
instabilities when necessary remedial actions need to be applied as quickly as possible.
17
Parameter-based schemes measure variables for which a significant change confirms the occurrence of a critical event.
This is also a form of open-loop control but with indirect event detection. The indirect method is mainly used to detect
remote switching of breakers (e.g., at the opposite end of a line) and significant sudden changes which can cause
instabilities, but may not be readily detected directly. To provide timely remedial action execution, the measured variables
may include power, angles, etc., and/or their derivatives.
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Chapter 3 – Study and Documentation Requirements
•
Parameters and equipment status monitored as inputs to the SPS (e.g., voltage, current or power flow, breaker
position) and specific monitoring points and locations
•
Under what conditions the SPS is armed (e.g., always armed, armed for certain system conditions, actuation
thresholds)
•
Whether arming is accomplished automatically or manually, if required
•
Arming criteria – analog quantities and/or equipment status monitored to determine existence of the system
condition for which SPS is armed (e.g., generation/load patterns, reactive power reserves, facility loading)
•
Action taken – for example: transmission facilities switched in or out; generators tripped, runback, or started; load
dropped; tap setting changed (phase-shifting transformer); controller set-point changed (AVR, SVC, HVdc
converter); turbine fast valving or generator excitation forcing; braking resistor insertion
•
Time to operate, including intentional time delays (e.g., timer settings) and inherent delays (e.g., relay operating
time)
•
Information with sufficient detail necessary to model the SPS.
SPS Database
PRC-013-0, Requirement R1 requires the Regional Reliability Organization to maintain an SPS database, including data on
design objectives, operation, and modeling of each SPS. Similar to the other requirements presently assigned to the
Regional Reliability Organization, this requirement should be assigned to a user, owner, or operator of the bulk power
system. To minimize the number of databases and facilitate sharing of information with entities that require SPS data to
plan and operate the bulk power system, this requirement should be assigned to the Planning Coordinator. The Planning
18
Coordinator should be required to provide its database to NERC for the purpose maintaining a continent-wide data base
that NERC would make available to Reliability Coordinators, Transmission Operators, Balancing Authorities, Planning
Coordinators, and Transmission Planners that require this data. The database should contain information for each SPS as
described above in the section titled, Data Submittals by Entities that Own SPS.
18
The requirement in a NERC Reliability Standard would be applicable to the Planning Coordinator; the responsibility for
NERC to maintain a continent-wide database should be addressed outside the standard.
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Chapter 4 – Operational Requirements
Due to their unique nature, SPS may have special operational considerations, with potentially differing requirements among
the proposed types for monitoring, notification of status, and the response time required to address SPS failure.
Furthermore, consideration should be given to the documentation of procedures for operator interaction with SPS, and
how operators should respond to SPS failures.
One entity should be assigned primary responsibility for monitoring, coordination, and control of an SPS. Depending on the
complexity, this responsible party may be a Reliability Coordinator, Balancing Authority, or Transmission Operator. Complex
SPS may have multiple owners or affected entities, including different functional entities and the chain of notification and
control should be clearly established.
Monitoring of Status
Existing NERC Reliability Standard IRO-005-3.1a, Requirement R1.1 requires Reliability Coordinators to monitor SPS.
Similarly PRC-001-1, Requirement R6 requires Balancing Authorities and Transmission Operators to monitor SPS. The SPS
standards should establish the level of monitoring capability that must be provided by the SPS owner. Classification of the
SPS will dictate its design criteria and may lend itself to different levels of monitoring.
All SPS should be monitored by SCADA/EMS with real-time status communicated to EMS that minimally includes whether
the scheme is in-service or out-of-service, and the current operational state of the scheme. For SPS that are armed
manually the arming status may be the same as whether the SPS is in-service or out-of-service. For SPS that are armed
automatically these two states are independent because an SPS that has been placed in-service may be armed or unarmed
based on whether the automatic arming criteria have been met. In cases where the classification of the SPS requires
redundancy, the minimal status indications should be provided for each system. The minimum status is sufficient for
operational purposes; however, where possible it may be useful to provide additional information regarding partial failures
or the status of critical components to allow the SPS owner to more efficiently troubleshoot a reported failure. Whether
this capability exists will depend in part on the design and vintage of equipment used in the SPS. While all schemes should
be required to provide the minimum level of monitoring, new schemes should be designed with the objective of providing
monitoring similar to what is provided for microprocessor-based protection systems.
Similarly, the SCADA/EMS presentation to the operator would need to indicate the criticality of the scheme (e.g., through
the use of audible alarms and a high priority in the alarm queue). The operator would be expected to know how to respond
depending on the nature of the issue detected, as some partial SPS failures might not result in a complete failure of the
scheme.
In cases where SPS cross ownership and operational boundaries, it is important that all entities involved with the SPS are
provided with an appropriate level of monitoring.
Notification of Status
Since the owner and operator of an SPS or component are often different organizations, and because SPS may cross entity
boundaries, it is important that the SPS status is communicated appropriately between entities. Existing NERC Reliability
Standards already require some level of notification of SPS status by Reliability Coordinators, Balancing Authorities and
19
Transmission Operators. Furthermore, SPS owners (e.g., Transmission Owner, Generator Owner) should be responsible
for communicating scheme or component issues to the operating organizations (e.g., Transmission Operator, Generator
Operator), who should then be responsible for communicating the issues to the involved Reliability Coordinator, Balancing
Authority, and other Transmission Operators or Generator Operators that might rely on the SPS (for example, in setting
operating limits).
The required timing associated with such notification will depend on the type of scheme; for example, the misoperation of
a Type PS or ES scheme would require rapid notification to all interested parties. In general, the more critical a scheme is to
the reliability of the system, the then more important its notification and response; however, it is also important that some
19
See, for example, IRO-005-3.1a Requirement R9 and PRC-001-1, Requirement R6.
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Chapter 4 – Operational Requirements
level notification be made for all schemes, due to the complex nature of SPS and their interaction with each other, to allow
entities to understand the reliability impact of a neighboring entity’s SPS failure or misoperation.
Response to Failures
As with many of the other issues, the response time required to address SPS failure is tightly coupled to the potential
impact of the SPS as well as the operating conditions at the time of failure. For example, if the SPS is intended to address an
event with a significant impact such as an IROL, then any corrective action in response to a misoperation would need to be
20
taken in 30 minutes or less, consistent with the TV associated with the IROL. On the other hand, depending on the
operating conditions, a particular scheme’s unavailability may not result in an adverse impact to reliability. Actions taken
following an SPS failure should consider whether the failure affects dependability or security of the SPS and the potential
impact to reliability.
Generally speaking, the SPS failure modes are known and the necessary corrective actions are documented (e.g.,
contingency plans) so that the system can be placed in a safe operating state. In any case, a full or partial failure of an SPS
requires that the system performance level provided by having the SPS in service is met, or a more conservative and safe
operating condition would need to be achieved, in a timeframe appropriate for the nature of the SPS and operating
conditions. When one system of a redundant SPS fails, the action taken by the operator may depend on the system
conditions the SPS is installed to address and the operating conditions at the time of the failure. For example, an operator
may respond to failure of one system by operating to higher equipment ratings when an SPS is installed to address thermal
loading violations. However, the operator may not be able to rely on the remaining system of a redundant SPS when the
SPS is installed to prevent instability, system separation, or cascading outages, in which case the operator must reduce
transfers or take other actions to secure the system.
Operational Documentation
Operational documentation is necessary to provide the operator with enough information to understand all aspects of the
scheme and is used to provide knowledge transfer as staff changes occur. Overall documentation requirements are
identified in the section on Study and Documentation Requirements; however, the operator does not require all
information provided by the SPS owner for the database maintained by the Planning Coordinator. The operational
documentation is sometimes called a “description of operations” and provides the operation actions for the following
areas:
•
General Description – This provides an overview of the purpose of the scheme including the monitoring, set points
and actions of the scheme. The operator and other stake holders can use this information to understand the need
for the scheme.
•
Operation – This will provide the specific information concerning, arming, alarming, and actions taken by this
scheme including the monitoring points of the scheme. The operator can use this information to provide triage and
plan a course of action concerning restoration of the electric system. This information should provide an
understanding of what has operated, why these elements have been impacted, and possible mitigations or
restoration activities.
•
Failures, Alarms, Targeting – This information will provide the operator and first responders with descriptions of
alarms and targets and the actions needed when the scheme is rendered unusable either during maintenance or
because of a failure. The instructions will guide the operator on how to respond to component failures that
partially impair the scheme or those failures that might disable entire scheme.
Regulatory agencies provide oversight of these schemes and require owners of these schemes to provide descriptions and
operational information. NERC PRC-015 requires owners to provide description of schemes and the Study and
Documentation Requirements section of this report proposes specific documentation requirements for inclusion in a
revised standard. In addition to NERC, some Regional Entities also require SPS owners to provide the Region with additional
information concerning the operations of the schemes. Some regional regulatory agencies also require the owners to verify
that they have taken certain actions after a misoperation or a failure of these schemes.
20
Specifically, TV is discussed in NERC Reliability Standard IRO-009-1, Requirement R2.
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Chapter 5 – Analysis of SPS Operations
Operations of SPS provide an opportunity to assess their performance in actual operating power systems, as opposed to
assessing the impact through a preconceived set of system studies. Analysis of SPS operations is presently addressed in
PRC-012-0 and PRC-016-0.1, which establish requirements for Regional Reliability Organizations and SPS owners
respectively. PRC-012-0 requires that each Regional Reliability Organization establish a regional definition of an SPS
misoperation (R1.6), as well as requirements for analysis and documentation of corrective action plans for all SPS
misoperations (R1.7). PRC-016-0.1 requires that SPS owners analyze their SPS operations and maintain a record of all
misoperations in accordance with their regional SPS review procedure (R1) and that SPS owners take corrective actions to
avoid future misoperations (R2).
PRC-012-0 is one of the standards identified in FERC Order No. 693 as a fill-in-the-blank standard and this standard
therefore is not mandatory and enforceable. SAMS and SPCS have not identified any rationale for having regional
definitions of an SPS misoperation or regional processes for analyzing SPS operations. Establishment of a continent-wide
definition and review process will facilitate meaningful metrics for assessing the impact of SPS misoperations on bulk power
system reliability. Rather than revising PRC-012-0 to assign responsibility for developing regional definitions and review
processes to a user, owner, or operator of the bulk power system, this report recommends that one continent-wide
definition and review process should be established through the NERC Reliability Standard Development Process, and that
criteria be established for SPS owners to follow a continent-wide review process in place of the existing requirements in
PRC-016-0.1.
SPS Misoperation Definition
Establishing a definition of an SPS misoperation must account for the many different aspects affecting whether operation of
an SPS achieves its desired effect on power system performance. In addition to aspects traditionally considered in assessing
protection system misoperations such as failure to operate and unnecessary operation, analysis of an SPS operation also
must consider whether the action was properly initiated and whether the initiated action achieved the desired power
system performance. This report proposes that a tiered definition be used to assess which aspects of an SPS operation are
reportable for metric purposes, which require analysis and reporting to the Reliability Coordinator and Planning
Coordinator, and which require a corrective action plan. The following definition is recommended for an SPS misoperation.
SPS Misoperation
A SPS Misoperation includes any operation that exhibits one or more of the following attributes:
a.
Failure to Operate – Any failure of a SPS to perform its intended function within the designed time when
system conditions intended to trigger the SPS occur.
b.
Unnecessary Operation – Any operation of a SPS that occurs without the occurrence of the intended system
trigger condition(s).
c.
Unintended System Response – Any unintended adverse system response to the SPS operation.
d.
Failure to Mitigate – Any failure of the SPS to mitigate the power system conditions for which it is intended.
The SPS review process should include requirements based on the SPS misoperation definition as follows:
•
The SPS owner must provide analysis of all misoperations to its Reliability Coordinator and Planning Coordinator.
•
The SPS owner must develop and implement a corrective action plan for all SPS misoperations.
•
Reporting for reliability metric purposes should be limited to SPS misoperations that exhibit attributes (a) or (b) of
the proposed definition, but should be addressed outside PRC-016-1, in a manner similar to the process under
development for reporting protection system misoperations in Project 2010-05.1 Protection Systems: Phase 1
(Misoperations).
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Chapter 5 – Analysis of SPS Operations
SPS Operation Review Process
The review process should be included in a revised version of PRC-016 and PRC-012-0 should be retired upon approval of a
continent-wide definition and revised PRC-016. The SPS operation review process should require that SPS owners analyze
all SPS operations in sufficient detail to determine whether or not the response of the power system to the SPS operation is
appropriate to meeting the purpose of the SPS. This requirement should be applied uniformly to all SPS types. The time
required to review each SPS operation will vary with the complexity of the SPS.
The analysis of each operation should include:
•
The power system conditions which triggered the SPS.
•
A determination of whether or not the SPS responded as designed.
•
An analysis of the power system response to the SPS operation.
•
An analysis of the effectiveness of the SPS in mitigating power system issues it was designed to address. This
analysis should identify whether or not those issues existed or were likely to occur at the time of the SPS
operation.
•
Any unintended or adverse power system response to the SPS operation.
For each SPS operation, the analysis should identify the power system conditions which existed at the time of the SPS
operation. These conditions should be analyzed to determine whether or not the SPS operation was appropriate. This part
of the analysis is to determine both whether or not the SPS operated as designed, and whether or not the conditions the
SPS is intended to mitigate were present at the time of SPS operation.
Some SPS use a proxy to determine the possible existence of a system problem. For example, the opening of a generator
outlet may cause an overload remote from the generator. An SPS could monitor the status of the outlet and run back
generation to avoid the possible overload, rather than monitoring the loading on the potentially impacted element. The
analysis should determine whether the SPS responded to the loss of outlet, and whether the overload actually would have
occurred without SPS operation.
The analysis should also examine the response of the system to the SPS operation. This part of the analysis is to determine
whether or not the SPS is effective in its intended mitigation, and if it has unforeseen adverse or unnecessary impacts on
the power system.
As noted with the proposed definition above, the reporting requirements for each SPS misoperation should vary based on
the attributes of the misoperation. The following discussion proposes reporting requirements and provides rationale for the
type of SPS misoperation to which each should apply.
1.
The SPS owner should be required to provide analysis of the misoperation to its Reliability Coordinator and
Planning Coordinator for all SPS misoperations. The report should be provided to the Reliability Coordinator and
the Planning Coordinator because such misoperations may require a reevaluation of the SPS under the review
process proposed in the Study and Documentation Requirements section. The report should include the corrective
action to assist the Reliability Coordinator and Planning Coordinator in confirming whether the SPS requires
reevaluation.
2.
The SPS owner should be required to develop and implement a corrective action plan for all SPS misoperations.
Reporting details of the corrective action plan should be limited to purposes supporting reliability. As noted above,
the report to the Reliability Coordinator and Planning Coordinator should include corrective actions. If an SPS must
be removed from service or its operation is modified pending implementation of the corrective action plan, the
status must be reported to the Reliability Coordinator, Transmission Operator, or Balancing Authority.
3.
The SPS owner should be required to report for reliability metric purposes any SPS misoperation that involves a
failure to operate or unnecessary operation. These attributes are analogous to protection system misoperations
that must be reported and involve a failure of the SPS to operate per its installed design. The mechanism for
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Chapter 5 – Analysis of SPS Operations
requiring reporting for reliability metric purposes should be similar to the process for reporting protection system
misoperations under development in Project 2010-05.1: Protection Systems: Phase 1 (Misoperations).
4.
The SPS owner should not be required to report or develop corrective action plans for other failures associated
with an SPS that are not associated with an SPS operation or failure to operate, such as:
•
Failure to Arm – Any failure of a SPS to automatically arm itself for system conditions that are intended to
result in the SPS being automatically armed;
•
Unnecessary Arming – Any automatic arming of a SPS that occurs without the occurrence of the intended
arming system condition(s); and
•
Failure to Reset – Any failure of a SPS to automatically reset following a return of normal system conditions, if
the system design requires automatic reset.
These types of failures can be corrected by the SPS owner without involving the Reliability Coordinator and the
Planning Coordinator, and are analogous to a protection system owner identifying a failed power supply on a relay. If
the failure has not resulted in a misoperation then reporting and corrective action plans are not required. It should be
noted however, that operational requirements apply and if an SPS must be removed from service the status must be
reported to the Reliability Coordinator, Transmission Operator, or Balancing Authority.
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Chapter 6 – Recommendations
Definition
The existing SPS definition in the NERC glossary lacks clarity and specificity necessary for consistent identification and
classification of SPS. The following strawman definition is proposed.
Special Protection System
A scheme designed to detect predetermined system conditions and automatically take corrective actions,
other than the isolation of faulted elements, to meet system performance requirements identified in the
NERC Reliability Standards, or to limit the impact of: two or more elements removed, an extreme event,
or Cascading.
Subject to the exclusions below, such schemes are designed to maintain system stability, acceptable
system voltages, acceptable power flows, or to address other reliability concerns. They may execute
actions that include but are not limited to: changes in MW and Mvar output, tripping of generators and
other sources, load curtailment or tripping, or system reconfiguration.
The following schemes do not constitute an SPS in and of themselves:
a)
Underfrequency or undervoltage load shedding
b) Locally sensing devices applied on an element to protect it against equipment damage for nonfault conditions by tripping or modifying the operation of that element, such as, but not limited
to, generator loss-of-field or transformer top-oil temperature
c)
Autoreclosing schemes
d) Locally sensed and locally operated series and shunt reactive devices, FACTS devices, phaseshifting transformers, variable frequency transformers, generation excitation systems, and tapchanging transformers
e)
Schemes that prevent high line voltage by automatically switching the affected line
f)
Schemes that automatically de-energize a line for non-fault operation when one end of the line is
open
g)
Out-of-step relaying
h) Schemes that provide anti-islanding protection (e.g., protect load from effects of being isolated
with generation that may not be capable of maintaining acceptable frequency and voltage)
i)
Protection schemes that operate local breakers other than those on the faulted circuit to
facilitate fault clearing, such as, but not limited to, opening a circuit breaker to remove infeed so
protection at a remote terminal can detect a fault or to reduce fault duty
j)
Automatic sequences that proceed when manually initiated solely by an operator
k)
Sub-synchronous resonance (SSR) protection schemes
l)
Modulation of HVdc or SVC via supplementary controls such as angle damping or frequency
damping applied to damp local or inter-area oscillations
m) A Protection System that includes multiple elements within its zone of protection, or that isolates
more than the faulted element because an interrupting device is not provided between the
faulted element and one or more other elements
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Chapter 6 – Recommendations
Classification
SPS should be classified based on the type of event to which the SPS responds and the consequence of misoperation.
Classification of SPS facilitates standard requirements commensurate with potential reliability risk. Four classifications are
proposed:
•
Type PS: planning – significant,
•
Type PL: planning – limited,
•
Type ES: extreme – significant, and
•
Type EL: extreme – limited.
The planning classification applies to schemes designed to meet system performance requirements identified in the NERC
Reliability Standards, while the extreme classification applies to schemes designed to limit the impact of two or more
elements removed, an extreme event, or Cascading.
The significant classification applies to a scheme for which a failure to operate or inadvertent operation of the scheme can
result in non-consequential load loss greater than or equal to 300 MW, aggregate resource loss (tripping or runback of
generation or HVdc) greater than the largest Real Power resource within the interconnection, loss of synchronism between
two portions of the system, or negatively damped oscillations. The limited classification applies to a scheme for which a
failure to operate or inadvertent operation would not result in a significant impact.
Applicability to Functional Model Entities
Three of the existing SPS-related reliability standards (PRC-012-0, PRC-013-0, and PRC-014-0) assign requirements to the
Regional Reliability Organization. These standards are not mandatory and enforceable because FERC identified them as fillin-the-blank standards in Order No. 693. This report recommends that requirements be reassigned to users, owners, and
operators of the bulk power system in accordance with the NERC Functional Model. The following recommendations are
included in the report:
•
Review of new or modified SPS – assign to Reliability Coordinators and Planning Coordinators.
•
SPS database maintenance – assign to Planning Coordinators; have Planning Coordinators submit databases to
NERC for maintenance of a continent-wide database.
•
Assessment of existing SPS – assign Planning Coordinators and Transmission Planners responsibility to include SPS
assessments in annual transmission planning assessments; assign Reliability Coordinators responsibility to
coordinate a periodic assessment of SPS design and coordination.
Revisions to Reliability Standards
Figure 1 provides a high-level overview of recommendations related to the six PRC standards that apply to SPS.
Recommendations include consolidating the six existing standards into three standards.
•
Combine all requirements pertaining to review, assessment, and documentation of SPS (presently in PRC-012-0,
PRC-013-0, PRC-014-0, and PRC-015-0) in one new standard, PRC-012-1. The requirement in PRC-012-0 for regional
procedures for reviewing SPS misoperations is superseded by recommendations for revisions to PRC-016-0.1. The
requirement in PRC-012-0 for regional maintenance and testing requirements is superseded by PRC-005-2.
•
Requirements pertaining to analysis and reporting of SPS misoperations should be revised in a new standard, PRC016-1. Due to the significant difference between protection systems and SPS, the subject of SPS misoperations
should not be included in a future revision of PRC-004.
•
Requirements pertaining to maintenance and testing of SPS already have been translated to PRC-005-2 by the
Project 2007-17 Protection System Maintenance & Testing drafting team.
Additional detail is provided in Table 2 in Appendix C – Mapping of Requirements from Existing Standards. This table
summarizes the recommendations for how each requirement in the existing six SPS-related standards should be mapped to
revised standards. The more significant recommendations are summarized below.
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Chapter 6 – Recommendations
PRC-012-0
RRO
Review Procedure
PRC-013-0
RRO
Database
PRC-014-0
RRO
Assessment
PRC-015-0
SPS Owner
•Change applicability to RC and PC
•Establish a uniform continent-wide SPS
review procedure
•Eliminate regional procedures for SPS
misoperations; address in PRC-016-1
•Change applicability to PC
•Establish continent-wide data requirements
•Require PC to submit database to NERC to
establish a continent-wide database
PRC-012-1
RC, PC, TP, and
SPS Owner
•Change applicability to PC and TP for annual
assessment and RC for five-year assessment
•Expand assessment requirements for
coordination of SPS and protection systems
Review, Assessment,
and Documentation
•Keep applicable to SPS owner
•Develop detailed list of data that SPS
owners must submit
Data & Documentation
PRC-016-0.1
SPS Owner
Misoperations
PRC-017-0
SPS Owner
Maintenance & Testing
•Keep applicable to SPS Owner
•Continent-wide definition of SPS
misoperation
•Continent-wide requirements for analysis
and reporting
PRC-016-1
•Keep applicable to SPS owner
•Requirements mapped to PRC-005-2
•Recommend additional requirements to
address complexity of SPS and nonprotection system components used in SPS
PRC-005-2
SPS Owner
Misoperations
SPS Owner
Maintenance & Testing
Figure 1 – Recommended Mapping of Existing PRC Standards
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Chapter 6 – Recommendations
Standard PRC-012-1 – SPS Review, Assessment, and Documentation
•
SPS owners should be required to design Type PL and Type PS SPS so that a single SPS component failure does not
prevent the interconnected transmission system from meeting the performance requirements defined in NERC
Reliability Standards TPL-001-0, TPL-002-0, or TPL-003-0.
•
Existing requirements for regional procedures for reviewing new or modified SPS should be replaced with a
continent-wide procedure assigned to Reliability Coordinators and Planning Coordinators to assure a wide-area
view of both planning and operational aspects of SPS.
•
Annual transmission planning assessments should include an assessment by the Planning Coordinator and
Transmission Planner to review the operation, coordination, and effectiveness of SPS, including the effect of
correct operation, a failure to operate, and inadvertent operations.
•
Periodic comprehensive assessments (every five years or less) of SPS should be performed by the Reliability
Coordinator, with support as requested from other entities, to assess whether SPS are still necessary, serves their
intended purpose, meet relevant design criteria, coordinate with other SPS, UFLS, UVLS, and protection systems,
and do not have unintended adverse consequences on reliability.
•
Detailed continent-wide requirements for data submittals should be established for SPS owners proposing new or
modified SPS. Detailed recommendations are included in this report.
•
Planning Coordinators should be assigned responsibility for maintaining databases containing all information
submitted by SPS owners. Planning Coordinators should be required to submit their databases to NERC so that
NERC can maintain and make available a continent-wide SPS database.
Standard PRC-016-1 – SPS Misoperations
•
PRC-016-1 should include a continent-wide definition of SPS misoperation based on the strawman definition
proposed in this report.
•
PRC-016-1 should include a continent-wide process for analysis of SPS operations and reporting SPS misoperations,
including requirements for SPS owners to develop corrective action plans and provide analysis of SPS
misoperations to Reliability Coordinators and Planning Coordinators.
•
Reporting SPS operation and misoperation data for reliability metric purposes should be addressed outside PRC016-1, in a manner similar to the process under development for reporting protection system misoperations in
Project 2010-05.1 Protection Systems: Phase 1 (Misoperations).
Standard PRC-005-2 – Protection System Maintenance and Testing
•
Maintenance and testing requirements for SPS should be expanded in the NERC Reliability Standards to address
the complexity of testing SPS and the maintenance of non-protection system components used in SPS. These
subjects should be addressed in a future revision of PRC-005 or development of a separate standard.
Recommendations to Be Included in Other Standards
This report discusses some aspects of SPS that are not addressed in the six SPS-related PRC standards. Recommendations
should be incorporated in appropriate NERC Reliability Standards.
•
SPS owners should be required to provide disturbance monitoring equipment to permit analysis of SPS
performance following an event.
•
Operating entities should be required to provide operators with documentation of procedures for operator
interaction with SPS, and how operators should respond to SPS failures.
•
All SPS should be monitored by SCADA/EMS with real-time status communicated that minimally includes whether
the scheme is in-service, out-of-service, and the current operational state of the scheme.
•
One entity should be assigned responsibility for monitoring, coordination, and control of an SPS.
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Appendix A – Modeling and Simulation Considerations
The addition of two stable control systems does not necessarily result in a stable composite control system; the same is
true for SPS. Although the SPS may not be directly linked in their actions, their composite actions and effect on the electric
system for commonly-sensed system conditions or perturbations can often behave as a single control system. Therefore, it
is imperative that they be evaluated for their potential to interact with each other, particularly during a system disturbance.
The composite interaction of multiple SPS, or of SPS with UFLS, UVLS, or other protection systems could result in system
instability or cascading.
Because of the complexity of some schemes, modeling them in system simulation is currently performed most often by
monitoring their trigger conditions and manually mimicking their intended actions such as changing system configuration,
switching reactive devices, and adjusting or tripping generation. Such manual manipulations in powerflow and dynamics
studies are only effective when studying a single SPS unless an iterative process is used. Even then, manual manipulation
may not be effective and may not be possible in studying the simultaneous actions of multiple SPS that could potentially
interact with each other. The difficulty is most significant when considering the potential interaction of parameter-based
SPS, since interaction with event-based SPS would occur only if the initial event and SPS operation caused a second event to
occur.
It is sometimes possible to simulate the behavior of a single SPS through simulation tools such as user-defined scripts using
vendor-provided or open-source programming capability, or standard relay models in the typical modeling and simulation
software packages. However, doing so for the myriad of SPS that may exist, even in a portion of an interconnection, is
cumbersome. Furthermore, simulating multiple SPS in real-time operations tools (e.g., EMS) for real-time contingency
analysis is extremely difficult and often requires new and innovative algorithm and software development. In addition,
models used in real-time systems are often abridged or reduced equivalents and may not permit accurate representation of
a particular SPS’s functions. All of these issues are extremely problematic given the sheer number of SPS in North American
interconnections.
To assure SPS will function in a coordinated fashion may require that they be modeled and studied from their design
inception in the planning horizon, through pre-seasonal system studies that determine transfer capabilities, and in the
operating horizon from day-ahead planning through the real-time contingency analysis that system operators depend on
for guidance. Present analysis methods are limited by the capability of the software tools and management of the SPS, and
in some cases protection system, data. The industry should put emphasis on future developments in these areas.
General Considerations for Simulations
This section puts forth a number of factors, limitations, objectives, and overall guiding principles that a standard drafting
team should consider in development of a new SPS standard with respect to the requirements for modeling and simulation,
including data and process requirements necessary to support accurate and meaningful studies of SPS by Transmission
Planners.
This report assumes that the modeling and simulation activities to be addressed are those performed for the planning
horizon by Transmission Planning personnel. It is assumed that studies are performed using commercial off-the-shelf
software packages and using databases derived from the interconnection-wide series of powerflow and dynamics cases.
Studies using EMS based tools (e.g., study tools built into state estimators, real-time contingency analysis software, etc.) for
real-time operations are not within the scope of this appendix.
It is important however, that the Transmission Planner share the results of planning horizon studies with operations
personnel such that the impacts of SPS are effectively understood for the operating horizon also. This can be accomplished
in a number of ways. Where operations support staff have similar study tools, sharing of the powerflow/dynamics cases,
models, simulation scripts and similar data would enable them to evaluate SPS operation (or misoperation) for the
operating horizon. Providing alarm or action limits for observable parameters (i.e., those that could be monitored in the
operating environment) related to SPS operation would be another possibility. In this case, the parameters may be a direct
indication or a proxy value that is indicative of the system condition of concern. Regardless of the process employed, the
overriding consideration is that study results are adequately translated into actionable intelligence that is available to and
understood by the system operator. While this is not intended to create a recommendation for a specific SPS standard
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Appendix A – Modeling and Simulation Considerations
requirement, how this would ultimately be accomplished should be kept in mind as SPS standards are developed and
implemented.
As a general rule, SPS are conceived by transmission planning engineers and implemented by protection and control
engineers. To some extent, the engineers in these two groups are concerned with different aspects of SPS operation and
use different terminology to describe SPS (and other system) functions. For example, a transmission planner may consider a
protection system component failure to be a contingency while a protection engineer may consider this to be a design
consideration. Transmission planning engineers conceive an SPS as a solution to system-level problems. Their focus is on
the “big picture” functional operation of the SPS for specific system level conditions. Protection and control engineers
implement an SPS via detailed design using various sensors, relays, etc. Their focus is on efficiently implementing the
functional requirements as they understand them to be. It is imperative that the planning engineers effectively
communicate the requirements of the SPS to protection engineers and monitor the design and implementation of the
scheme to ensure that the SPS is implemented and functions as prescribed by the planner.
The planning and protection engineers should also consult with the operations personnel to ensure that possible systemlevel events which might result in unintended SPS operation are considered. Involving operations personnel at each stage of
the design process will help ensure that the range of operating conditions likely to be encountered in the real world
(including outages), as well as practical operating considerations, are also adequately considered in the SPS design and
implementation.
An explicit requirement should exist to represent the salient features of SPS operation in a form that can be readily shared
with, understood by, and used in simulations by other Transmission Planners. Simulation of SPS in powerflow or dynamic
studies may involve a combination of using standard relay models, various monitoring features, and scripts or program
code to adequately simulate the functioning of the SPS. These may include user-defined scripts using vendor-provided or
open-source programming capability, or standard relay models in the typical modeling and simulation software packages
(either executed during solution-run time or as user-written dynamic models), etc. Transmission Planners generally have
their own individual preferences as to how to reflect these functions when performing simulations. Additionally, different
Transmission Planning organizations have different levels of expertise in developing scenarios to reflect actual system
operation and performing simulations based on those scenarios. Therefore, it is important that the modeling information to
be used by other Transmission Planning engineers as input (including run scripts) in simulations be simple, understandable
and well documented. Any scripts or models provided need to be “open source” in nature and well-documented to enable
independent verification. The use of user models, FORTRAN object code, compiled scripts, and similar which make it
difficult for the receiving Transmission Planner to review and understand how the SPS model functions must be avoided.
In addition to providing the relay models, program code/script, and similar input as part of the database, a summary
document should be provided explaining the SPS. The information shared must include a summary and guidance document
which includes the following, as applicable.
•
An overview explanation of the basic functioning of the SPS, describing when and how it operates
•
A listing of the setpoints applicable to the SPS (e.g., relay trip settings, etc.)
•
A summary overview of how the SPS is being simulated via relay models, simulation scripts that may be provided
•
Specific bus numbers, branch identifiers, machine identifiers, etc. should be referenced to help the Transmission
Planner receiving this information understand how the SPS is being simulated
SPS modeling information should be readily available as part of the interconnection-wide modeling processes, but not an
integral part of an interconnection-wide case year database. Specific recommendations are included in the chapter on study
and documentation requirements.
Because of the special nature of SPS, it is not practical or even possible to include them in the interconnection-wide load
flow and/or dynamic database case years in the classic sense (e.g., such as one would include a generator or FACTS device
model). Additionally, it is simply not necessary to model all SPS for all simulations. The reality is that an SPS in the Northeast
will likely have very little impact on the results of simulations focused on the Southeast. Therefore, including all SPS in all
simulations places an unreasonable burden on Transmission Planners. However, due consideration should be given to the
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Appendix A – Modeling and Simulation Considerations
interaction of a given SPS with other SPS. Note that geographical distance alone may not be sufficient justification not to
consider the interaction of several SPS.
However, it is important that information about all SPS be available for use, as deemed appropriate by the Transmission
Planners whose systems may be affected by the SPS operation (or misoperation). It is also important the relevant
parameter-based SPS be modeled concurrently in simulations to appropriately evaluate potential interactions among the
SPS.
Therefore, the data management process for providing SPS information for simulations purposes should include the
following considerations.
•
Sufficiently detailed SPS information and documentation as described above can be managed as part of the
interconnection-wide powerflow and dynamic case creation process.
•
Providing the models and simulation scripts alone is not sufficient. A functional description to assist the
Transmission Planner in understanding how these modeling/simulation elements work to emulate the SPS function
is necessary in order for the Transmission Planner to properly simulate and interpret the results of simulations
involving the SPS.
•
The SPS information may reside separately from the interconnection-wide powerflow and dynamic cases, but a
clear association to each case must be evident.
•
Each Transmission Planner will be able to select the SPS that are relevant to the simulation they are performing.
Engineering judgment, with a documented reason, for excluding SPS from simulations is acceptable.
•
Where included, the impact of multiple SPS and their interaction should be reasonably accounted for in the
simulation activities.
It is envisioned that Transmission Planners will generally include only those SPS that, in their judgment, are relative to the
simulations being performed and/or could potentially interact with other SPS being included in these simulations. However,
it would be prudent to have some big picture check for unintended SPS interaction. Therefore, a joint, interconnection-wide
study or assessment should be periodically performed to evaluate potential interactions among SPS across the entire
interconnection. Such a study or assessment should include modeling and simulation of all of the SPS throughout the
interconnection. A periodicity of five years for this joint study is suggested as an appropriate time frame.
Use of SPS Simulations in Transmission Planning Studies
SPS are used as alternatives to transmission infrastructure to support reliable system operation for identified concerns. As
such, these schemes must be analyzed in transmission planning analyses just as any other transmission system addition
would be, with a focus on:
•
Operation as expected for the design case of concern
•
Understanding the potential for operation beyond the original design intent
•
Determining if there is a potential for failure to operate to rectify the design case of concern.
In system planning, the types of studies which are typically performed to determine system performance are powerflow
and dynamic simulations and analyses. SPS need to be modeled in both of these types of studies.
Powerflow (i.e., steady-state) SPS modeling techniques which could be employed include:
•
Explicit modeling of the SPS monitoring and consequent actions with scripting and programming automatically
called during powerflow processing
•
Explicit modeling of the actuation of the SPS in contingencies which are expected to cause the SPS to actuate
•
Contingencies are included in the analysis with and without the SPS actuated
•
Monitoring of system performance to determine if system conditions would actuate an SPS
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Appendix A – Modeling and Simulation Considerations
o
The monitoring occurs for all contingencies examined
o
Any result indicating potential actuation of an SPS is rerun with the SPS actuated
Dynamic (i.e., stability) SPS modeling techniques which could be employed include:
•
Explicit modeling of the SPS in the dynamic simulation with a model that includes the monitoring and consequent
actions during the dynamic simulations
•
Explicit modeling of the actuation of the SPS in contingencies which are expected to cause the SPS to actuate
•
The dynamic/stability contingencies are included in the analysis with and without the SPS actuated
•
Monitoring of SPS trigger elements (voltage, current, flow and/or frequency on system elements or element
status) to determine if actuation of an SPS would have actuated
o
Rerun the simulation with the SPS actuated if the monitored results indicate potential actuation of the SPS
The SPS modeling techniques used in system planning should be based upon modeling information provided by the SPS
owner which clearly describes what the SPS senses and the consequent actions taken when its triggering needs are met.
The need for accurate modeling information can be demonstrated with an example. In the example, two SPS exist in an
area. One SPS trips a large generating plant for loss of a transmission circuit due to first swing stability concerns. This SPS
acts within cycles of the initiating line loss. The second SPS inserts a series reactor into a transmission circuit to limit flow
and eliminate an overload on the circuit. The second SPS acts within seconds (5 seconds for this example) of the overload
condition occurring.
Steady state studies of the area where these SPS exist would examine the representative cases (sets of system conditions)
and contingency sets for the study in question. If the power flow software allowed, a post-solution program could be run to
test if the actuating circumstances for each SPS were met; if so, the contingent solution would be rerun and tested again for
any other SPS which would actuate. If the power flow software did not have this flexibility, the engineer could include an
SPS actuation for those contingencies expected to trigger the SPS and run that expanded contingency list; the results could
be examined with attention paid to the loading for the circuit protected by the second SPS. Any contingencies which caused
an overload on the triggering circuit could be rerun with the SPS actuated.
Since both SPS act within the dynamic simulation timeframe, the SPS should be modeled or monitored in stability
simulations. Dynamic models could exist for both SPS. Should the flow on the SPS-triggering line exceed the flow actuation
setpoint for the required time duration, the dynamic simulation would capture the impact of the reactor insertion and the
SPS actuation. If the SPS were not explicitly modeled, their trigger values could be monitored (i.e., the status or flow on the
line for the first SPS and the flow on the potentially overloaded circuit for the second SPS). The monitored data channels
would be examined after each simulation to determine if the simulation needed to be rerun while modeling the
appropriate SPS actions.
The goal for modeling SPS in studies is to confirm that they will operate to correct the intended system concerns as
necessary to preserve acceptable system performance. In addition, the analyses provide understanding for system planning
and operations on when and how the use of the SPS may change over time. This information may be critical for system
operations staff to maintain reliable system operation.
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Appendix B – Operational Considerations
This information is a high level list of important issues and concerns if performing SPS analyses in real-time operations.
Real-time SPS Evaluation
Current system conditions must be identified before evaluating whether an SPS would perform its function and achieve its
desired outcome. Results of security analysis should be required to indicate whether an SPS should be armed (if armed
manually) and whether an SPS will operate for a given contingency. Security analysis should model operation of the SPS in
addition to the initiating contingency when the SPS is armed.
SPS evaluation often cannot be done with SCADA input alone. Some non-SCADA input may be needed; for example, limits
from off-line studies are converted into inputs available in the Energy Management System (EMS). The inputs that support
SPS evaluation and operation need to be codified in operating guides and presented on operator displays for ease of use
and operation. Custom code and displays are generally required to aggregate all needed information for usage by engineers
and operators in real time.
The impact of SPS operation on facilities external to the SPS owner/operator needs to be jointly considered and
communicated to external entities and appropriately accounted for in EMS. Furthermore, the effects of external
contingencies on the SPS triggers should be accounted for within EMS and known to operators.
SPS evaluation typically involves the testing of a limited set of relevant contingencies, requiring the use Real-Time
Contingency Analysis (RTCA). In some cases, a dc solution to identify thermal issues is adequate; in other cases, a full ac
solution is required (e.g., where triggers are voltage dependent).
Some EMS are not robust enough to compute ac solutions in EMS/RTCA. Depending on the classification of an SPS (e.g.,
significant), an EMS/RTCA with such limited capability would be insufficient to evaluate the impact of the SPS. In such cases
it is necessary to establish other means, such as supplemental off-line tools or delegation of this analysis to an entity that
has this capability, to study the operational impacts of the SPS.
If the EMS/RTCA does not reach a solved state, then the SPS cannot be evaluated. For example, some EMS/RTCA will fail to
solve or fail to converge upon the creation of islands in the model. In these cases, SPS modeling may require custom
software solutions.
Multiple Decision-Making Capability
When evaluating SPS in EMS/RTCA, intermediate steps must be modeled and intermediate states must be evaluated. It
should be assumed that an SPS may suffer a full or partial failure and that system conditions will change as the SPS
operates. Adverse conditions may arise during intermediate steps that lead to undesired outcomes or put the system into
an unplanned operating state.
The post-contingency, pre-SPS-operation state must be known to assess system conditions before the SPS action can be
evaluated. For example, the loss of a large nuclear station automatically activates a large emergency core cooling load. This
new system state would require a re-solution to check post-contingent node voltage (i.e., with the load connected) before
consideration of SPS activation and results can occur. This requires that several stages and intermediate actions be modeled
in the evolution of the final system topology to ensure that the system can reach the desired end-state.
Information Management
Each SPS may have its own set of arming and activation triggers. Examples include equipment status, line loading and
voltage. These triggers may be complex, and could affect the alarming capability required of EMS.
Changes to EMS models may require long lead times before an SPS can be implemented; for example, changes to models
often require pushing through multiple staged software environments. Entities should use software designs that are flexible
to accommodate timely changes to SPS models that might not be tied to the network model database release schedule.
When implementing an SPS before the EMS model can be updated, it is necessary to establish other means, such as
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Appendix B – Operational Considerations
supplemental off-line tools or delegation of this analysis to an entity that has this capability, to study the operational
impacts of the SPS.
Modeling Simplicity and Usability
Complex SPS schemes require due diligence to maintain and support. Entities should be required to develop and document
an efficient approach to SPS control. An entity’s strategy should allow for concurrent and/or consecutive SPS actions.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-012-0
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning
to use an SPS shall have a documented
Regional Reliability Organization SPS review
procedure to ensure that SPSs comply with
Regional criteria and NERC Reliability
Standards. The Regional SPS review
procedure shall include:
PRC-012-1 should define a continent-wide SPS
review procedure conducted by the Reliability
Coordinator and Planning Coordinator.
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-012-0
R1.1. Description of the process for
submitting a proposed SPS for
Regional Reliability Organization
review.
PRC-012-1 should define a continent-wide SPS
review procedure conducted by the Reliability
Coordinator and Planning Coordinator.
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-012-0
R1.2. Requirements to provide data that
describes design, operation, and
modeling of an SPS.
PRC-012-1 should define continent-wide
requirements for SPS owners to provide data that
is clear and understandable to all entities that
require this information to plan and operate the
bulk power system.
See Data Submittals by Entities that Own SPS on
pp. 18-19.
PRC-012-0
R1.3. Requirements to demonstrate that the
SPS shall be designed so that a single
SPS component failure, when the SPS
was intended to operate, does not
prevent the interconnected
transmission system from meeting
the performance requirements
defined in Reliability Standards TPL001-0, TPL-002-0, and TPL-003-0.
PRC-012-1 should require that all Type PS and PL
SPS are designed so system performance
requirements are met in the event of a single
component failure within the SPS.
See SPS Single Component Failure Requirements
on p. 14-15
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
PRC-012-0
PRC-012-0
PRC-012-0
PRC-012-0
Requirement
Proposal
Comments
PRC-012-1 should require that an entity proposing
a new or modified SPS should be required to
submit studies that demonstrate the operation,
coordination, and effectiveness of the SPS,
including the impacts of a correct operation, a
failure to operate, and inadvertent operation.
See Review and Approval of New or Modified SPS
on p. 16.
R1.5. Requirements to demonstrate the
proposed SPS will coordinate with
other protection and control systems
and applicable Regional Reliability
Organization Emergency procedures.
PRC-012-1 should require that an entity proposing
a new or modified SPS should be required to
submit studies that demonstrate the operation,
coordination, and effectiveness of the SPS,
including the impacts of a correct operation, a
failure to operate, and inadvertent operation.
See Review and Approval of New or Modified SPS
on p. 16.
R1.6. Regional Reliability Organization
definition of misoperation.
A continent-wide definition of an SPS
misoperation should be established.
See SPS Misoperation Definition on p. 22.
Do not carry forward to revised standards.
The need for this requirement is eliminated by
establishing continent-wide requirements in PRC016-1. See SPS Operation Review Process on pp.
23-24.
R1.4. Requirements to demonstrate that the
inadvertent operation of an SPS shall
meet the same performance
requirement (TPL-001-0, TPL-002-0,
and TPL-003-0) as that required of the
contingency for which it was
designed, and not exceed TPL-003-0.
R1.7. Requirements for analysis and
documentation of corrective action
plans for all SPS misoperations.
PRC-012-0
R1.8. Identification of the Regional Reliability
Organization group responsible for
the Regional Reliability Organization’s
review procedure and the process for
Regional Reliability Organization
approval of the procedure.
Do not carry forward to revised standards.
The need for this requirement is eliminated by
establishing a continent-wide review procedure
within PRC-012-1. See Review and Approval of
New or Modified SPS on pp. 16-17.
PRC-012-0
R1.9. Determination, as appropriate, of
maintenance and testing
requirements.
Do not carry forward to revised standards.
The need for this requirement is eliminated by
establishing continent-wide maintenance and
testing requirements within PRC-005-2.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-012-0
R2. The Regional Reliability Organization shall
provide affected Regional Reliability
Organizations and NERC with documentation
of its SPS review procedure on request
(within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-013-0
R1. The Regional Reliability Organization that has
a Transmission Owner, Generator Owner, or
Distribution Provider with an SPS installed
shall maintain an SPS database. The database
shall include the following types of
information:
PRC-012-1 should require that each Planning
Coordinator maintain a database, and provide the
database to NERC for the purpose of maintaining
a continent-wide database.
See SPS Database on p. 19.
PRC-013-0
R1.1. Design Objectives — Contingencies and
system conditions for which the SPS
was designed,
This information is included in a comprehensive
list of data requirements to be provided by the
SPS owner and maintained in a database by the
Planning Coordinator.
See Data Submittals by Entities that Own SPS on
pp. 18-19 and SPS Database on p. 19.
PRC-013-0
R1.2. Operation — The actions taken by the
SPS in response to Disturbance
conditions, and
This information is included in a comprehensive
list of data requirements to be provided by the
SPS owner and maintained in a database by the
Planning Coordinator.
See Data Submittals by Entities that Own SPS on
pp. 18-19 and SPS Database on p. 19.
PRC-013-0
R1.3. Modeling — Information on detection
logic or relay settings that control
operation of the SPS.
This information is included in a comprehensive
list of data requirements to be provided by the
SPS owner and maintained in a database by the
Planning Coordinator.
See Data Submittals by Entities that Own SPS on
pp. 18-19 and SPS Database on p. 19.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-013-0
R2. The Regional Reliability Organization shall
provide to affected Regional Reliability
Organization(s) and NERC documentation of
its database or the information therein on
request (within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-014-0
R1. The Regional Reliability Organization shall
assess the operation, coordination, and
effectiveness of all SPSs installed in its Region
at least once every five years for compliance
with NERC Reliability Standards and Regional
criteria.
PRC-012-1 should require the Planning
Coordinator and Transmission Planner to assess
SPS in annual transmission planning assessments
and require the Reliability Coordinator to conduct
a periodic review every five years, or sooner if
significant changes are made to the system
topology or operating characteristics that may
impact the coordination among SPS and between
SPS and UFLS, UVLS, and other protection
systems.
See Periodic Comprehensive Assessments of SPS
Coordination on p. 17.
PRC-014-0
R2. The Regional Reliability Organization shall
provide either a summary report or a
detailed report of its assessment of the
operation, coordination, and effectiveness of
all SPSs installed in its Region to affected
Regional Reliability Organizations or NERC on
request (within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-014-0
R3. The documentation of the Regional Reliability
Organization’s SPS assessment shall include
the following elements:
PRC-012-1 should require the Reliability
Coordinator to document its periodic
assessments. The documentation should include
the same elements required in a study supporting
approval of a new or modified SPS.
See Review and Approval of New or Modified SPS
on pp. 16-17 and Assessment of Existing SPS on p.
17.
This list of elements includes:
• Entity conducting the study
• Study completion date
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-014-0
R3.1. Identification of group conducting the
assessment and the date the
assessment was performed.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-014-0
R3.2. Study years, system conditions, and
contingencies analyzed in the
technical studies on which the
assessment is based and when those
technical studies were performed.
This list of elements includes:
• Study years
• System conditions
• Contingencies analyzed
• Study completion date
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-014-0
R3.3. Identification of SPSs that were found
not to comply with NERC standards
and Regional Reliability Organization
criteria.
PRC-012-1 should require the Planning
Coordinator and Transmission Planner document
and submit any issues identified in the annual
assessment to the Reliability Coordinator.
PRC-012-1 should require the Reliability
Coordinator to document and submit any issues
identified in the periodic assessment to the SPS
owner.
See Assessment of Existing SPS on p. 17.
PRC-014-0
R3.4. Discussion of any coordination
problems found between a SPS and
other protection and control systems.
PRC-012-1 should require the Reliability
Coordinator to request the Planning Coordinator
and Transmission Planner to assess and document
whether the SPS is still necessary, serves its
intended purpose, meets performance criteria,
coordinates with other SPS, UFLS, UVLS, and
protection systems, and does not have
unintended adverse consequences on reliability.
See Periodic Comprehensive Assessments of SPS
Coordination on p. 17.
PRC-014-0
R3.5. Provide corrective action plans for noncompliant SPSs.
PRC-012-1 should require that if issues are
identified in an annual or periodic assessment,
the Reliability Coordinator and Planning
Coordinator determine, in consultation with the
SPS owner, whether a corrective action plan is
required, and if so, whether the SPS can remain in
service until a corrective action plan is
implemented.
If a corrective action plan is required, PRC-012-1
should require the SPS owner to submit an
application for a new or modified SPS.
See Assessment of Existing SPS on p. 17.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-015-0
R1. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall maintain a list of and provide data for
existing and proposed SPSs as specified in
Reliability Standard PRC-013-0_R1.
PRC-012-1 should define continent-wide
requirements for SPS owners to provide data that
is clear and understandable to all entities that
require this information to plan and operate the
bulk power system.
See Data Submittals by Entities that Own SPS on
pp. 18-19.
PRC-015-0
R2. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall have evidence it reviewed new or
functionally modified SPSs in accordance with
the Regional Reliability Organization’s
procedures as defined in Reliability Standard
PRC-012-0_R1 prior to being placed in
service.
Do not carry forward to revised standards. PRC012-1 should have a requirement for the SPS
owner to file an application for approval of an
SPS, which assures that the SPS is reviewed in
accordance with the continent-wide review
procedure prior to being placed in service.
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-015-0
R3. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall provide documentation of SPS data and
the results of Studies that show compliance
of new or functionally modified SPSs with
NERC Reliability Standards and Regional
Reliability Organization criteria to affected
Regional Reliability Organizations and NERC
on request (within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-016-0.1
R1. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall analyze its SPS operations and maintain
a record of all misoperations in accordance
with the Regional SPS review procedure
specified in Reliability Standard PRC-0120_R1.
PRC-016-1 should establish a continent-wide
process for analyzing and reporting SPS
misoperations.
See SPS Operation Review Process on pp. 23-24.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-016-0.1
R2. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall take corrective actions to avoid future
misoperations.
PRC-016-1 should establish a requirement that
the SPS owner should be required to develop and
implement a corrective action plan for SPS
misoperations.
See SPS Operation Review Process on pp. 23-24.
PRC-016-0.1
R3. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall provide documentation of the
misoperation analyses and the corrective
action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
R1. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall have a system maintenance and testing
program(s) in place. The program(s) shall
include:
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Tables 1-1 – 1-5, and Table 2.
PRC-017-0
PRC-017-0
21
R1.1. SPS identification shall include but is
not limited to:
PRC-017-0
R1.1.1. Relays.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-1.
PRC-017-0
R1.1.2. Instrument transformers.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-3.
PRC-017-0
R1.1.3. Communications systems,
where appropriate.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-2.
21
Mapping for requirements in PRC-017-0 are adapted from the mapping document developed by the Project 2007-17 Protection System Maintenance & Testing
drafting team.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
PRC-017-0
Requirement
R1.1.4. Batteries.
Proposal
Comments
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-4.
PRC-017-0
R1.2. Documentation of maintenance and
testing intervals and their basis.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1 and R2.
PRC-017-0
R1.3. Summary of testing procedure.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1, Tables 1-1 – 1-5, and Table 2.
PRC-017-0
R1.4. Schedule for system testing.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1 and R2.
PRC-017-0
R1.5. Schedule for system maintenance.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1 and R2
PRC-017-0
R1.6. Date last tested/maintained.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R3 and associated Measures, R4
and associated Measure, and Data Retention.
Addressed by Project 2007-17, Protection System
Maintenance and Testing; this requirement is not
carried forward to the revised standard.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-017-0
R2. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall provide documentation of the program
and its implementation to the appropriate
Regional Reliability Organizations and NERC
on request (within 30 calendar days).
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Appendix D – Standards Committee Request for Research;
January 9, 2011
Request for Research
Project 2010-05.2
Phase 2 of Protection Systems: SPS and RAS
Introduction
NERC’s Standards Committee has tentatively identified this project for initiation in late 2012. Prior to then, there is a need
for additional research and scoping of the project to determine:
• What is the problem that this project will try to solve?
• Is the development of a standard the appropriate manner to solve that problem, or should alternative approaches
be used?
• If a standard is appropriate, what is the recommended solution to the problem?
Results based standards projects use the approach of defining the needs, goals, and objectives for the project. For this
project, we would like your assistance in this effort. Below is a draft problem statement for your consideration.
Need (Problem )
Special Protection Systems (SPS) and Remedial Action Schemes (RAS) can misoperate and negatively impact the
reliability of the BES.
Does the need above correctly document the concern described in the attached draft SAR?
Do you agree that this is a problem that needs to be addressed?
Is a standard the appropriate vehicle to address this problem, or should an alternative approach be used? If an alternative,
is recommended, what would that alternative be?
If development of a standard is appropriate, then please consider the following Goal
Goal (Solution)
Require the analysis, reporting, and correction of Misoperations of SPS and RAS.
Request
Please provide the Standards Committee with the following information:
•
•
•
•
An updated Need/Problem (or a statement of concurrence with the draft presented here)
A statement indicating whether or not you believe this problem is one which needs to be addressed
If you agree the problem needs to be addressed, a suggestion for how to address the problem
If you suggest a standard be developed to address the problem, then please provide
o An updated goal (or a statement of concurrence with the draft presented here)
o A set of objectives in support of that goal
o If you have any suggested changes to the attached draft SAR, please propose them
o If you have specific recommendations for requirements language or additional information, please include
them
Thank you in advance for your assistance.
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Appendix E – Scope of Work Approved by the Planning
Committee; June 8, 2011
As s e s s m e n t o f Sp e cia l P r o t e ct io n Sys t e m St a n d a r d s a n d Re g io n a l
P r a ct ice s
Proposal:
The SPCS proposes to conduct an assessment of the SPS-related PRC standards and definition of SPS, conduct an
assessment of existing regional practices summarizing commonality and differences, and to document its findings in a
report to the Planning Committee that can serve as a reference document for a standard drafting team that ultimately will
be assigned to review these standards. If deemed appropriate, the report could be used to support a Compliance
Application Notice (CAN) to address part of this issue until a revised definition and standard(s) are developed. The SPCS
further proposes this activity should be a joint effort with the Transmission Issues Subcommittee (TIS).
Rationale:
•
The SPCS scope calls for providing subject matter expertise for NERC Standards related to protection systems and
controls, and the SPCS work plan includes an assignment to review all existing PRC-series Reliability Standards, to
advise the Planning Committee of its assessment, and to develop Standards Authorization Requests, as appropriate, to
address any perceived deficiencies.
•
The SPCS has reviewed all PRC standards except the group of SPS standards. The SPCS had started assessment of these
standards, but the assessment was deferred due to other priority work such as the Power Plant and Transmission
System Protection Coordination technical reference document.
•
The SPCS has reviewed its work plan and determined that this is the next logical project for the SPCS. Work on the
Transmission System Phase Backup Protection reliability guideline is wrapping up at this time and the SPCS can make
the SPS review one of two priority activities for this year (the other is the document addressing operation of protection
systems in response to power swings).
•
The SPCS believes that a thorough review of SPS-related PRC standards would benefit from the expertise of TIS and the
SPCS recommends a joint SPCS/TIS effort coordinated by the SPCS. This proposal has been reviewed with and is
supported by TIS.
•
The SPCS proposes to conduct an assessment of the standards and definition of SPS, and conduct an assessment of
existing regional practices summarizing commonality and differences among the various regional practices.
•
The SPCS believes that differences among regional practices must be resolved through a formal process; a consensus
opinion of what constitutes an SPCS would lack standing unless it is vetted through a stakeholder process. The SPCS
proposes to document its findings in a report that can serve as a reference document for a standard drafting team that
ultimately will be assigned to review these standards. If deemed appropriate, the report could be used to support a
CAN to address part of this issue until a revised standard(s) is developed.
•
The scope of work for such a review is significant and direction should come through the NERC Planning Committee as
the body to which SPCS and TIS report.
•
The SPCS believes that an appropriate time frame for completing this report would be to submit a draft to the Planning
Committee at its March 2012 meeting. The SPCS and TIS believe this schedule is appropriate to support a thorough
review.
Approved by the NERC Planning Committee
June 8, 2011
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Appendix F – System Analysis and Modeling Subcommittee
Roster
John Simonelli
Chair
Director - Operations Support Services
ISO New England
Jonathan E Hayes
RE – SPP
Reliability Standards Development Engineer
Southwest Power Pool, Inc.
K. R Chakravarthi
Vice Chair
Manager, Interconnection and Special Studies
Southern Company Services, Inc.
Kenneth A. Donohoo
RE – TRE
Director System Planning
Oncor Electric Delivery
G Brantley Tillis, P.E.
RE – FRCC
Manager, Transmission Planning Florida
Progress Energy Florida
Hari Singh
RE – WECC
Transmission Asset Management
Xcel Energy, Inc.
Kiko Barredo
RE – FRCC – Alternate
Manager, Bulk Transmission Planning
Florida Power & Light Co.
Kent Bolton
RE – WECC – Alternate
Staff Engineer
Western Electricity Coordinating Council
Thomas C. Mielnik
RE – MRO
Manager Electric System Planning
MidAmerican Energy Co.
Digaunto Chatterjee
ISO/RTO
Manager of Transmission Expansion Planning
Midwest ISO, Inc.
Salva R. Andiappan
RE – MRO – Alternate
Manager - Modeling and Reliability Assessments
Midwest Reliability Organization
Patricia E Metro
Cooperative
Manager, Transmission and Reliability Standards
National Rural Electric Cooperative Association
Donal Kidney
RE – NPCC
Manager, System Compliance Program Implementation
Northeast Power Coordinating Council
Eric Mortenson, P.E.
Investor-Owned Utility
Principal Rates & Regulatory Specialist
Exelon Business Services Company
Bill Harm
RE – RFC
Senior Consultant
PJM Interconnection, L.L.C.
Amos Ang, P.E.
Investor-Owned Utility
Engineer, Transmission Interconnection Planning
Southern California Edison
Mark Byrd
RE – SERC
Manager - Transmission Planning
Progress Energy Carolinas
Bob Cummings
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Gary T Brownfield
RE – SERC – Alternate
Supervising Engineer, Transmission Planning
Ameren Services
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Appendix G – System Protection and Control Subcommittee
Roster
William J. Miller
Chair
Principal Engineer
Exelon Corporation
Samuel Francis
RE – TRE
System Protection Specialist
Oncor Electric Delivery
Philip B. Winston
Vice Chair
Chief Engineer, Protection and Control
Southern Company
David Penney, P.E.
RE – TRE – Alternate
Senior Reliability Engineer
Texas Reliability Entity
Michael Putt
RE – FRCC
Manager, Protection and Control Engineering Applications
Florida Power & Light Co.
Baj Agrawal
RE – WECC
Principal Engineer
Arizona Public Service Company
Mark Gutzmann
RE – MRO
Manager, System Protection Engineering
Xcel Energy, Inc.
Miroslav Kostic
Canada Provincial
P&C Planning Manager, Transmission
Hydro One Networks, Inc.
Richard Quest
RE – MRO – Alternate
Principal Systems Protection Engineer
Midwest Reliability Organization
Sungsoo Kim
Canada Provincial
Section Manager – Protections and Technical Compliance
Ontario Power Generation Inc.
George Wegh
RE – NPCC
Manager
Northeast Utilities
Michael J. McDonald
Investor-Owned Utility
Principal Engineer, System Protection
Ameren Services Company
Quoc Le
RE – NPCC -- Alternate
Manager, System Planning and Protection
NPCC
Jonathan Sykes
Investor-Owned Utility
Manager of System Protection
Pacific Gas and Electric Company
Jeff Iler
RE – RFC
Principal Engineer, Protection and Control Engineering
American Electric Power
Charles W. Rogers
Transmission Dependent Utility
Principal Engineer
Consumers Energy Co.
Therron Wingard
RE – SERC
Principal Engineer
Southern Company
Joe T. Uchiyama
U.S. Federal
Senior Electrical Engineer
U.S. Bureau of Reclamation
David Greene
RE – SERC -- Alternate
Reliability Engineer
SERC Reliability Corporation
Daniel McNeely
U.S. Federal – Alternate
Engineer - System Protection and Analysis
Tennessee Valley Authority
Lynn Schroeder
RE – SPP
Manager, Substation Protection and Control
Westar Energy
Philip J. Tatro
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
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Appendix H – Additional Contributors
Forrest Brock
Transmission Compliance Specialist
Western Farmers Electric Cooperative
Robert Creighton
Sr. Engineering Specialist, Transmission Planning
Nova Scotia Power, Inc.
Tom Gentile
Senior Director, Transmission Northeast
Quanta Technology
Bryan Gwyn
Senior Director, Protection and Control Asset Management
Quanta Technology
Gene Henneberg
Staff Protection Engineer
NV Energy
Greg Henry (formerly NERC Staff Coordinator for SAMS)
Lead Engineer, Smart Integrated Infrastructure
Black & Veatch
Bobby Jones
Planning Manager – Stability
Southern Company Services
John O’Connor
Principal Engineer
Progress Energy Carolinas
Slobodan Pajic
Senior Engineer, Energy Consulting
GE Energy Management
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Appendix I – Revision History
Revision History
Version
Date
Modification(s)
0
March 5, 2013
Initial Document
0.1
April 18, 2013
Appendix A – Correction to remove trade names and replace with generic language
in the section, General Considerations for Simulation
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Project 2008-02 Undervoltage Load Shedding
Recommended Coordination Plan | March 14, 2014
Background
Project 2008‐02 Undervoltage Load Shedding (“UVLS Project”) proposes to consolidate and retire PRC‐010‐0, PRC‐020‐1, PRC‐021‐1, and PRC‐
022‐1 to create PRC‐010‐1 – Undervoltage Load Shedding. During development, the drafting team identified the following necessary
corresponding changes to meet the design of PRC‐010‐1:
1) Modify PRC‐004‐3 – Protection System Misoperation Identification and Correction, which excludes UVLS, to include certain types of
UVLS programs as part of its applicable facilities.
2) Retire three requirements in EOP‐003‐2 – Load Shedding Plans whose required performance is reflected in proposed PRC‐010‐1.
3) Modify the current NERC Glossary definition of the term Special Protection System (SPS), which excludes UVLS, to include a subset of
UVLS programs that are more appropriately categorized as SPSs and covered by SPS‐related standards.
In order to make the necessary changes, the UVLS Project needs to coordinate with ongoing development work in three active NERC standard
development projects as follows:
Project 2010‐05.1 Protection Systems: Phase 1 (Misoperations) (“Misoperations Project”)
Project 2009‐03 Emergency Operations (“EOP Project”)
Project 2010‐05.2 Protection Systems: Phase 2 (Special Protection Systems) (“SPS Project”)
Current Recommended Plan
As a result, NERC has identified a preferred project plan to coordinate the above‐mentioned projects to properly align legacy standard
retirements and revised standard implementations due to the differences in each project’s timing. In short, the revised SPS definition, the
UVLS Project, and the EOP Project will be presented simultaneously to industry, the NERC Board of Trustees, and applicable regulatory
authorities. An illustrative diagram of this coordination appears on the next page. This plan is subject to change as necessary.
1) The UVLS Project will address the conforming changes needed to PRC‐004 after PRC‐004‐3 is complete. How and when this will occur
depends on when PRC‐004‐3 obtains approval from the ballot body and is adopted by the NERC Board of Trustees.
2) The EOP and UVLS Projects will progress simultaneously and coordinate necessary changes.
3) The SPS Project is proposing to revise the definition of SPS in advance of revising the SPS standards. The UVLS Project will progress
simultaneously with the SPS definition revision in order to properly transfer certain aspects of the legacy UVLS standards into coverage
under the SPS standards.
Impacts
As a result of the necessary coordination above, the UVLS Project and the EOP Project are now timed by the schedule for the SPS Project,
which is targeting the approval of the revised SPS definition at the February 2015 NERC Board of Trustees meeting.
Additional Considerations
Of note, Project 2007‐17.3 Protection System Maintenance and Testing: Phase 3 (Sudden Pressure Relays) is beginning development on
version 4 of PRC‐005, which may consider use of a new defined term introduced by the UVLS Project. Therefore, this project may also
coordinate with the UVLS Project as needed.
Project 2008‐02 UVLS | Recommended Coordination Plan
2
Project 2009‐03 EOP
Retires requirements from EOP‐
003 that map to PRC‐010‐1
Project 2008‐02 UVLS
In development / waiting for
UVLS
Project 2010‐05.1 Misops
PRC‐010‐1
PRC‐004‐3
Retires PRC‐010, PRC‐020, PRC‐021, and
PRC‐022
Completed second additional
comment/ballot
Project 2010‐05.2 SPS
Will introduce an applicability change to
PRC‐004 when PRC‐004 is complete.
Revised SPS definition revision
will encompass a subset of UVLS
programs currently covered by
the legacy UVLS standards
In development / waiting for revised SPS
definition
Forming drafting team
February 2015
First SPS SDT Meeting
Revised SPS
Standards to BOT
June 2014
April 2015
UVLS and EOP
Standards and SPS
Defintion First
Ballot
UVLS and EOP
Standards and SPS
Definiton Petition
Package to FERC
Project 2008‐02 UVLS | Recommended Coordination Plan
TBD
UVLS and EOP
Standards and SPS
Definiton to BOT
April 2014
3
Standards Announcement
Project 2010-05.2 Phase 2 of Protection Systems
(Special Protection Systems)
Standard Authorization Request
Informal Comment Period Now Open through March 19, 2014
Now Available
A 30-day comment period for the Phase 2 of Protection Systems – Special Protection Systems
Standard Authorization Request is open through 8 p.m. Eastern on Wednesday, March 19, 2014.
Instructions for Commenting
The comment period is open through 8 p.m. Eastern on Wednesday, March 19, 2014. Please use
the electronic form to submit comments on the SAR. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is
posted on the project page.
For information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Individual or group. (20 Responses)
Name (11 Responses)
Organization (11 Responses)
Group Name (9 Responses)
Lead Contact (9 Responses)
Question 1 (20 Responses)
Question 1 Comments (20 Responses)
Question 2 (18 Responses)
Question 2 Comments (20 Responses)
Question 3 (0 Responses)
Question 3 Comments (20 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Yes
The annual assessment of SPS in transmission planning studies should be addressed within
Transmission Planning (TPL) standards. We recommend that Transmission Planning
requirements not be included in Protection and Control (PRC) standards.
No
Individual
Anthony Jablonski
ReliabilityFirst
Yes
ReliabilityFirst agrees with the scope of the SAR and believes these revised standards will
enhance reliability. Specifically a modified SPS definition will increase clarity and removal of
the RRO as the applicable entity from certain standards will remove the “fill-in the blank”
aspects and correctly make them enforceable on users, owners and operators of the BES.
Group
MRO NERC Standards Review Forum
Joseph DePoorter
Yes
The current draft of the SAR scope includes PRC-017 to avoid any gaps or overlap between
PRC-017 and the proposed SPS standard. Since the PRC-017 standard is scheduled to be
retired with the effective date of PRC-005-2, which is April 1, 2014, PRC-005-2 already
includes in its scope the maintenance and testing requirements of the Protection System
elements of a SPS. Therefore there is no gap, and addressing of PRC-017 in the SPS
standard creates overlap and potential double jeopardy (between PRC-005-2 and the SPS
standard). It is recommended that the maintenance and testing requirements of all of the
elements of the SPS be in the same standard and not split the requirements for the testing
of parts of the SPS into two standards. Since the specific requirements for the testing of the
"Protection System components" of a SPS are already in PRC-005, it seems to make more
sense to simply make PRC-005 apply to "all" components (parts) of a SPS, rather than
repeat the specific requirements for the testing in a second standard. While the NSRF
understands that SPS misoperations were not addressed in the recent PRC-004 revision, the
NSRF believes that SPS misoperations can be addressed under PRC-004-3 without any
further significant modifications. Once the definition of a SPS is clearly determined (part of
this project), the analysis of any operation (or lack of operation) of the scheme does not
need to be treated any differently than other Protection System analysis and correctoperation determination. It is recommended that the evaluation of proper/improper
operation of a SPS be included in PRC-004 rather than in a second Misoperation standard,
PRC-016. Once the definition of a SPS is well defined, it should be no more or less difficult
to determine if it operated correctly than any other protection scheme. The time frames for
review, possible involvement of multiple parties, and Corrective Action Plans aspects apply
directly to SPSs just as they do to ordinary Protection System schemes. The SAR scope
should be expanded to include more definition of the term, “functional modification.”
There will continue to be uncertainty and inconsistency regarding which SPS changes are a
“functional modification” until specific criteria and examples are developed. For instance,
the criteria and examples should be able to address the treatment of such changes as a
direct replacement of a failed SPS component failure (e.g. SEL-321 relay for SEL-321 relay),
upgrading a SEL-321 relay with a SEL-421 relay with the same logic, and using a different
logic to accomplish the same system result.
No
The NRSF has concerns that the proposed SPS definition in the technical paper remains
broad, lacks sufficient clarity and the specificity necessary for consistent identification /
classification of SPS systems across all eight regions. While the SPCS effort is commendable,
the definition remains overly broad and will continue to bring in protection systems that
don’t affect the security of the BES. This is evidenced by the long list of identified
exclusions. The drafting team cannot identify and exclude all possible protection schemes
that respond to non-fault conditions and entities will continue to identify more systems
that need to be excluded as there are many reasons to install specific protection systems.
The MRO NSRF suggests that the SAR allow room for the drafting team to consider
enhancements other than what is proposed in the SPCS technical paper. Perhaps a hybrid
definition / screening process followed by a specific BES system instability analysis are
needed to 1) clearly communicate the SPS definition intentions, and 2) identifying only BES
protection systems that are “Special” because they have a regional impact on BES security.
An example is the difference between a reverse power relay that trips a backfed 100kV and
greater BES bus (which should not be a special protection system), versus the SONGS
scheme that helped trigger the southwest power outage (which should be special due to its
security impact on the BES). The hybrid definition / screening process could start with an
English SPS definition similar to what was proposed by the SPCS allowing entities to quickly
screen protection systems for potential inclusions and exclusions similar to the BES
definition. This could be followed by a BES security impact analysis which would screen for
BES transmission instability, uncontrolled separation, and cascading using known and
understood power stability program stability analyses similar to the TPL standards. This
would provide repeatable concrete and measurable results that would clearly identify
protection schemes that had a BES security impact. Concrete and measurable criteria could
be specified using understood industry practices and IEEE papers or standards for
identifying when BES security was impacted through regional undamped and poorly
damped power system oscillations.
Individual
Jonathan Meyer
Idaho Power Co.
No
No
Individual
Oliver Burke
Entergy Services, Inc.
No
No
The centralized UVLS program should be considered as part of SPS.
Individual
Thomas Foltz
American Electric Power
Yes
The SAR proposes that PRC-017-0 be retired or revised, however this standard is already
approved to be retired under PRC-005-2.
No
We are hopeful that the establishment of SPS “types”, as detailed in the SPCS technical
report, may eliminate the need for regional variances.
We are encouraged by NERC’s willingness to pursue revision of the definition of Special
Protection Systems and impacted standards.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
No
Comments: These comments are submitted on behalf of the following PPL NERC Registered
Affiliates (“PPL”): Louisville Gas and Electric Company and Kentucky Utilities Company; PPL
Electric Utilities Corporation; PPL EnergyPlus, LLC; PPL Generation, LLC; PPL Susquehanna,
LLC and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions
(MRO, NPCC, RFC SERC, SPP, and WECC) for one or more of the following NERC functions:
BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.
No
None
Group
Southern Company: Southern Company Service, Inc.; Alabama Power Company; Georgia
Power Company; Gulf Power Company; Mississippi Power Company; Southern Company
Generation; Southern Company Generation and Energy Marketing
Wayne Johnson
Yes
The current draft of the SAR scope includes PRC-017-0. This standard is scheduled to be
retired with the effective date of PRC-005-2, which is 01 Apr 2014. PRC-005-2 already
includes in its scope the maintenance and testing requirements of the Protection System
elements of a SPS. It is recommended that the maintenance and testing requirements of all
of the elements of the SPS be in the same standard - either include the "Protection System
components" and "non-Protection System components" of a SPS in PRC-005 or in PRC-017,
and not split the requirements for the testing of parts of the SPS into two standards. Since
the specific requirements for the testing of the "Protection System components" of a SPS
are already in PRC-005, it seems to make more sense to simply make PRC-005 apply to "all"
components (parts) of a SPS rather than repeat the specific requirements for the testing in
a second standard. It is not clear how a SPS can have "non-Protection System components".
If a component is required in the composition of a SPS to achieve the desired operablity, it
seems implicit that it becomes a "Protection System component". Once the definition of a
SPS is clearly determined (part of this project), the analysis of any operation (or lack of
operation) of the scheme does not need to be treated any differently than other Protection
System analysis and correct-operation determination. It is recommended that the
evaluation of proper/improper operation of a SPS be included in PRC-004 rather than in a
second Misoperation standard, PRC-016. Once the definition of a SPS is well defined, it
should be no more or less difficult to determine if it operated correctly than any other
protection scheme. The time frames for review, possible involvement of multiple parties,
and Corrective Action Plans aspects apply directly to SPSs just as they do to ordinary
Protection System schemes.
Group
Florida Municipal Power Agency
Frank Gaffney
No
FMPA appreciates the efforts of the team and believes the definition is a significant
improvement over the former definition. There are only a few comments we are making in
response to this and the next two questions First is that we are of the opinion that Special
Protection Systems are indeed Protection Systems as defined in the NERC Glossary, and as
applicable to PRC-005-2 recently approved by FERC. The Applicability Section of PRC-005-2
at 4.2.4 reads: “Protection Systems installed as a Special Protection System (SPS) for BES
reliability.” If an SPS is not a Protection System, then what is the scope of testing required
in PRC-005-2 for an SPS? If an SPS is not a Protection System, should the scope of the SAR
be changed to include modifications to PRC-005-2? The SDT seems to depend on: “… SPS
are not limited to detecting faults or abnormal conditions and tripping affected equipment”
in expressing its opinion that SPSs are not Protection Systems; however, those terms are
not used in the Glossary definition of Protection Systems. There is nothing in the definition
of Protection System that would eliminate SPSs from being a subset of Protection Systems.
In addition, under the section “Voltage Threshold” of the paper that includes the proposed
definition, the paper states: “(a)ll elements, at any voltage level, of an SPS intended to
remediate performance issues on the bulk electric system (BES), or of an SPS that acts upon
BES elements, should be subject to the NERC requirements.” If the SPS is not a Protection
System that includes: (i) relays; (ii) communication systems; (iii) voltage and current sensing
devices; (iv) dc supply; and (v) control circuits as elements of the Protection System, then to
what does “all elements” refer?
No
The definition should not include brightlines. Brightlines already exist in at least two
standards that would just cause confusion over what brightline to use. The CIP-002-5
standard has a Medium Risk brightline criteria 2.9 of Attachment 1 to CIP-002-5 which
states: “2.9. Each Special Protection System (SPS), Remedial Action Scheme (RAS), or
automated switching System that operates BES Elements, that, if destroyed, degraded,
misused or otherwise rendered unavailable, would cause one or more Interconnection
Reliability Operating Limits (IROLs) violations for failure to operate as designed or cause a
reduction in one or more IROLs if destroyed, degraded, misused, or otherwise rendered
unavailable.” IRO-005, R9 uses a criteria of: “… a Special Protection System that may have
an inter-Balancing Authority, or inter-Transmission Operator impact (e.g., could potentially
affect transmission flows resulting in a SOL or IROL violation) …” Adding another set of
brightlines (for no apparent purpose contained within the standards but presumably for the
convenience of three of the Regions) that conflict with these brightlines already within the
standards will only bring confusion. Brightlines for SPSs shouldbe within each standard, not
within the definition. If the SDT does not agree, then, at minimum, the SAR should be
changed to modify CIP-002-5 and IRO-005 to align with the newly proposed brightlines. The
definition is exceptionally long. By removing the categories and brighlines from the
definition, it cuts the definition roughly in half.
The definition does not address automatic actions taken by an EMS, SCADA or DCS and
whether that would be considered an SPS. For instance, an EMS can be programmed to
perform automated switching (without human intervention) to relieve an overloaded
Facility in a similar manner to an SPS designed with relays or a programmable logic
controller. Would such automation cause the EMS to be an SPS and subject to PRC-005-2
requirements for testing?
Individual
Catherine Wesley
PJM Interconnection
Yes
Based on the high level information included in the SAR, PJM offers the following
comments: a. Recommend a new name for the project. It is not a phase 2 of the Protection
Misoperation standard effort as identified. It is a new project covering all aspects of SPSs,
and the present Project numbering and project name are confusing. b. Specific to the
strawman definition, for ‘d’ in the listing of schemes that do not constitute an SPS, the list
of equipment is very discrete/specific. Please revise to be more generic because if not
revised, could possibly leave out emerging technologies requiring future revision. c. For the
classifications identified, they should be static in their scope, not dynamic which would
result in potentially continued reevaluation of the classifications. In other words, base the
SPS types on the contingency mitigated not the results of the contingency. d. PJM is
reluctant to support adding the BA to the applicability of the standard since it is
administrative in nature; however, understands that the BA is the source of the information
(the largest generator unit in the BA area). Alternatives to making a new administrative
requirement include using the data request section of the RoP (section 1600). e. The
standard should not allow new permanent SPSs except for temporary installations that will
eventually be removed when permanent mitigation is built or for maintenance conditions.
No
Individual
Bill Fowler
City of Tallahassee
Yes
While TAL appreciates the need for consistency among regions in regards to the
classification of SPS, flexibility in this classification should be afforded the regions due to
valid geographical concerns. For this reason, TAL believes the classification component of
the proposed language should be independently developed from the SPS definition.
No
N/A
Individual
Karen Webb
City of Tallahassee - Electric Utility
Yes
While TAL appreciates the need for consistency among regions in regards to the
classification of SPS, flexibility in this classification should be afforded the regions due to
valid geographical concerns. For this reason, TAL believes the classification component of
the proposed language should be independently developed from the SPS definition.
Yes
TAL believes valid geographical concerns exist among regions, and therefore some
flexibility should be afforded in the classification of SPS.
Individual
Scott Langston
City of Tallahassee
Yes
While TAL appreciates the need for consistency among regions in regards to the
classification of SPS, flexibility in this classification should be afforded the regions due to
valid geographical concerns. For this reason, TAL believes the classification component of
the proposed language should be independently developed from the SPS definition.
Yes
TAL believes valid geographical concerns exist among regions, and therefore some
flexibility should be afforded in the classification of SPS.
TAL provides no comment
Group
PacifiCorp
Sandra Shaffer
No
Yes
PacifiCorp agrees with the Industry Need statement for this project and that the existing
NERC Glossary of Terms definition for a Special Protection System (SPS) or Remedial Action
Scheme (RAS) as used in the Western Interconnection lacks the clarity and specificity
necessary for consistent identification and classification of protection schemes as SPS or
RAS across the eight NERC Regions. This leads to inconsistent application of the SPS-related
NERC Reliability Standards. Phase 1 of Project 2010-05.1 addresses Misoperations of
Protection Systems (PRC-004-03). The implementation Plan for PRC-004-03 will require the
Western Electricity Coordinating Council (WECC) to modify Regional Reliability Standard
PRC-004-WECC-1 which has an attached Table, Major WECC Remedial Action Schemes
(RAS). As this Project 2010-05.2 Special Protection Systems (Phase 2 of Protection Systems)
is addressing all aspects of Special Protection Systems, including misoperations, NERC
should instruct WECC to review the PRC-004-WECC-1 Table, Major WECC Remedial Action
Schemes (RAS), and, to the extent possible, conform to NERC SPS/RAS definitions and
classifications developed in Project 2010-05.2 SPS Phase 2. In addition, the purpose of
WECC Criterion PRC-(012 through 014)-WECC-CRT-2 is to (1) establish a documented RAS
review procedure to ensure compliance with PRC-012-0, (2) establish a RAS database per
PRC-013-0, and (3) meet the Regional Reliability Organization / Reliability Assurer
requirements of PRC-014-0. This regional criterion will require modification upon
competition of Project 2010-05.2 SPS Phase 2, which is expected to provide a continentwide definition and classification of SPS/RAS.
Individual
Gul Khan
Oncor Electric Delivery Company LLC
No
See response to Question 3 which addresses Oncor’s comments regarding the System
Protection Control Subcommittee (SPCS) Technical Report.
No
The purpose of this SAR is stated to “develop continent-wide standards to address all
aspects of SPS.” Oncor interprets this to mean regional variance is not considered.
With respect to the System Protection Control Subcommittee (SPCS) Technical Report
(Report), Oncor provides the following comments. First, Oncor agrees with the proposed
SPS definition and encourages the SDT to keep the following in the exclusions; Static Var
Compensators (SVCs), Series/Shunt Capacitors, and Series/Shunt Reactors. Oncor believes
these devices, as used today, are part of “standard” business practice. Additionally, Oncor
has general concern about the SPS Operations Review Process as described on Page 23 of
the Report. SPS design is based on long-range planning data provided by the Planning
Authority. Tools to perform in depth real-time analysis are limited. Oncor believes that the
immediate assessment of an SPS operation should be limited to considering if it operated
as designed. As proposed in Appendix C of the Report, the new PRC-016 requirement which
replaces PRC-012-0 R1.7, adds real time SPS operation analysis. Oncor recommends the
SDT not require this level of analysis to PRC-016 and indicate that the SPS Operations
Review Process is for Mis-Operations only.
Individual
Nazra Gladu
Manitoba Hydro
Yes
(1) In the “Brief Description” section of the SAR, it is stated that the project will develop a
standard to address the “periodic comprehensive SPS assessments”. Are the periodic
comprehensive SPS assessments necessary given that an initial review has been completed
and annual assessments of SPS have been included in the transmission planning studies?
No
(1) General comment as a reminder to the SDT, consider keeping the new standard as
simple as possible and of minimum length. (2) General comment - consider replacing all
instances of the word “standard” with “NERC Reliability Standard”. (3) Page 3 - capitalize
the word “data” in the title for PRC-015-0 Special Protection System data and
Documentation. (4) Page 3 - capitalize and re-write “bulk power system” as “Bulk-Power
System”. (5) Page 3 - a ‘period’ is missing after the text “……into a Reliability Standard”.
Group
ACES Standards Collaborators
Jason Marshall
Yes
(1) In general, we are supportive of the concept of the SAR. We support developing a more
specific definition of SPS for consistent application and classification of SPSs across all NERC
regions. However, we do have some specific concerns identified below. (2) The SAR should
clarify what is meant by “planning, coordination, and design” and “review, assessment, and
documentation” of SPS. If by “planning, coordination, and design,” the SAR intends to
consider which facilities the SPS will open by performing planning studies and to consider
their impacts on one another in the same studies, we are supportive. If the engineering
design (e.g. such as what relays will be used, what CT settings will be) is what is intended,
we do not support the SAR as it is inconsistent with any other standard. For example, there
is no engineering design standard for Protection Systems. This would extend the standards
beyond what the original intention of the fill-in-the-blank unapproved standards.
Furthermore, inclusion of “review” and “assessment” is part of the confusion because we
interpret this to mean the analysis that is performed in the planning studies. Please clarify.
(3) In the “Brief Description” section, what is the difference between “annual assessments
of SPS in transmission planning studies” and “periodic comprehensive SPS assessments?”
Annual would be periodic. Please provide clarification.
No
(1) We have no additional comments. Thank you for the opportunity to comment.
Individual
David Jendras
Ameren
Yes
(1) Will the term RAS be eliminated, such that SPS is used consistently by all eight regions?
If RAS is retained then the statement “Also called Remedial Action Scheme” from the
present definition also needs to be retained. (2) Is our understanding correct that the scope
is to be limited to the 693 reliability standards?
No
We believe that the term ‘system’ is used in a myriad of ways in the NERC Glossary of
Terms. Thus we request revising the first sentence of the proposed SPS definition from the
SAMS-SPCS SPS Technical Reference to clarify ‘system’. We recommend the following: ‘A
scheme designed to detect predetermined Bulk Electric System (system) conditions and
automatically take corrective actions, other than the isolation of faulted elements, to meet
system performance requirements identified in the NERC Reliability Standards, or to limit
the impact of: two or more elements removed, an extreme event, or Cascading.’
Group
Bonneville Power Administration
Andrea Jessup
No
No
Group
SPP Standards Review Group
Robert Rhodes
Yes
We are concerned that the scope of this project may creep beyond the true purpose of
Special Protection Systems into the area of protection schemes used for individual facilities.
While we believe this is covered in the accompanying SPCS report, it is not spelled out
specifically in the SAR. It needs to be included to keep the SDT on track.
No
While we realize this is a standard question on SAR postings, it seems odd that it is included
in a project that is intended to pull the differing interpretations of SPS from the individual
Regions into a single, continent-wide effort. This being the case, we hope that regional
differences can be put aside.
We note the effort within the SPCS report to clearly state that SPS are not truly Protection
Systems and an effort was made to use lower case protection systems to stay away from
the conflict. This being the case, perhaps we should defer to the naming convention used in
WECC and designate these systems Remedial Actions Schemes.
PRC‐012‐2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 1 of PRC‐012‐2 corrects the applicability of the fill‐in‐the‐blank standards (PRC‐012‐1,
PRC‐013‐1, PRC‐014‐1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk‐Power System, and incorporates the reliability objectives of
all the RAS/SPS‐related standards. This draft of PRC‐012‐2 contains eleven (11) requirements
and measures, and the associated rationale boxes and corresponding technical guidelines.
There are also three (3) attachments within the draft standard incorporated via references in
the requirements. This draft of PRC‐012‐2 does not contain “Compliance” elements such as
VRFs, VSLs; they cannot be determined until requirement development is completed. PRC‐012‐
2 is posted for a 21‐day informal comment period to gather stakeholder input for use in the
standards development process.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Anticipated Actions
Date
Draft 1 of PRC‐012‐2 posted for informal comment
April 30 – May 20, 2015
45‐day formal comment period with ballot
July 2015
10‐day final ballot
October 2015
NERC Board (Board) adoption
November 2015
Draft 1 of PRC‐012‐2 – Remedial Action Schemes
April 2015
Page 1 of 28
PRC‐012‐2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
3.
Number:
Purpose:
PRC‐012‐2
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Transmission Planner
4.1.3. RAS‐owner – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.1.4. RAS‐entity – the Transmission Owner, Generator Owner, or Distribution
Provider designated to represent all owners of the RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See Implementation Plan for Project 2010‐05.3 PRC‐012‐2
Draft 1 of PRC‐012‐2 – Remedial Action Schemes
April 2015
Page 2 of 28
PRC‐012‐2 – Remedial Action Schemes
B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES); therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement (removal from service) must be completed prior to
implementation. A functional modification is any modification to a RAS beyond the
replacement of components that preserves the original functionality.To facilitate a review
that promotes reliability, the RAS‐entity must provide the reviewer with sufficient details
of the RAS design, function, and operation. This data and supporting documentation are
identified in Attachment 1 of this standard, and Requirement R1 mandates the RAS‐entity
provide them to the reviewing Reliability Coordinator (RC). The RC responsible for the
review will be the RC that coordinates the area where the RAS is located. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC would be responsible for
conducting either individual reviews or a coordinated review.
R1.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity shall submit the information identified in Attachment 1 to the
reviewing Reliability Coordinator(s). [Violation Risk Factor:] [Time Horizon:]
M1. Acceptable evidence is a copy of the Attachment 1 documentation and the dated
communications with the reviewing Reliability Coordinator(s) in accordance with
Requirement R1.
Rationale for Requirement R2: Requirement R2 mandates that the Reliability Coordinator
(RC) perform a review of a proposed new RAS or an existing RAS proposed for functional
modification or retirement (removal from service) in its RC area.
The RC is the functional entity best‐suited to perform the RAS reviews because it has a
wide‐area perspective of reliability that includes awareness of reliability issues in its
neighboring RC Areas. This wide‐area purview provides continuity in the review process
and better facilitates the coordination of interactions among separate RAS as well as the
coordination of interactions among RAS and other protection and control systems. The
selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS‐Entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entity that could be involved in the planning or
implementation of a RAS. The RC may designate a third party to conduct the RAS reviews;
however, the RC will retain the responsibility of compliance with this requirement.
Attachment 2 of this standard is a checklist provided to the RC to assist in identifying
important design and implementation aspects of RAS, and in facilitating consistent
reviews for each RAS submitted. The time frame of four full calendar months is consistent
with current utility practice; however, flexibility is provided by allowing the parties to
negotiate a different schedule for the review.
Draft 1 of PRC‐012‐2 – Remedial Action Schemes
April 2015
Page 3 of 28
PRC‐012‐2 – Remedial Action Schemes
Note: An RC may need to include this task in its reliability plan(s) for the Region(s) in
which it is located.
R2.
For each RAS submitted pursuant to Requirement R1, each reviewing Reliability
Coordinator shall, within four full calendar months of receipt of Attachment 1
materials, or on a mutually agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written feedback to the RAS‐entity.
[Violation Risk Factor:] [Time Horizon: ]
M2. Acceptable evidence may include, but is not limited to, date‐stamped reports, or
other documentation detailing the RAS review, and the dated communications with
the RAS‐entity in accordance with Requirement R2.
Rationale for Requirement R3: Requirement R3 mandates the RAS‐entity
address all reliability‐related issues identified by the Reliability Coordinator (RC)
during the RAS review, and obtain approval from the RC that the RAS
implementation can proceed. This interaction promotes reliability by minimizing
the introduction of inadvertent actions (risks) to the BES. A specific time period
for the RAS‐entity to respond to the RC’s review is not necessary because an
expeditious response is in the self‐interest of the RAS‐owner(s) to effect a
timely implementation. The review by the RC is intended to identify reliability
issues that must be resolved before the RAS can be put in service. The reliability
issues could involve dependability, security, or both. A more detailed
explanation of dependability and security is included in the Supplemental
Materials section of the standard.
R3.
Following the review performed pursuant to Requirement R2, the RAS‐entity shall
address each identified reliability‐related issue and obtain approval from each
reviewing Reliability Coordinator, prior to placing a new or functionally modified RAS
in‐service or retiring an existing RAS. [Violation Risk Factor:] [Time Horizon:]
M3. Acceptable evidence may include, but is not limited to, date‐stamped documentation
and date‐stamped communications with the reviewing Reliability Coordinator in
accordance with Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that a technical evaluation of
each RAS be performed at least once every 60 full calendar months. The purpose of
periodic RAS evaluation is to verify the continued effectiveness and coordination of the
RAS, as well as BES performance following an inadvertent RAS operation. This periodic
evaluation is needed due to possible changes in system topology and operating
conditions that may have occurred since the previous RAS evaluation (or initial review)
was completed. Sixty (60) full calendar months was selected as the maximum time frame
for the evaluation based on the time frames for similar requirements in Reliability
Standards PRC‐006‐1, PRC‐010‐1, and PRC‐014‐1. The RAS evaluation can be performed
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sooner if it is determined that material changes to system topology or system operating
conditions that could potentially impact the effectiveness or coordination of the RAS have
occurred since the previous RAS evaluation or will occur before the next scheduled
evaluation. The periodic RAS evaluation will typically lead to one of the following
outcomes: 1) affirmation that the existing RAS is adequate; 2) identification of changes
needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Parts 4.1, 4.2, 4.3) are planning
analyses which involve modeling of the interconnected transmission system;
consequently, the Transmission Planner (TP) is the functional entity best qualified to
perform the analyses. To promote reliability, the TP is required to provide the RAS‐
owner(s) and the Reliability Coordinator(s) with the results of each evaluation.
R4.
Each Transmission Planner shall perform an evaluation of each RAS within its planning
area at least once every 60 full calendar months and provide the RAS‐owner(s) and
the Reliability Coordinator(s) the results including any identified deficiencies. Each
evaluation shall determine whether: [Violation Risk Factor:] [Time Horizon:]
4.1. The RAS mitigates the System condition(s) or contingency(ies) for which it was
designed.
4.2. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
4.3. The inadvertent operation of the RAS satisfies the same performance
requirements as those required for the contingency for which it was designed or,
if no performance requirements apply, the inadvertent operation of the RAS
satisfies the requirements of Category P7 in Table 1 of NERC Reliability Standard
TPL‐001‐4, or its successor.
M4. Acceptable evidence may include, but is not limited to, date‐stamped reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and date‐
stamped communications with the RAS‐owner(s) and the Reliability Coordinator(s) in
accordance with Requirement R4.
Rationale for Requirement R5: Deficiencies identified in the periodic RAS evaluation
conducted by the Transmission Planner in Requirement R4 are likely to pose a reliability
risk to the BES due to the impact of either a RAS operation or incorrect operation. To
avoid this reliability risk, Requirement R5 mandates that the RAS‐owner(s) submit a
Corrective Action Plan that establishes the mitigation methods and timetable to address
the deficiency. Submitting the Corrective Action Plan to the Reliability Coordinator (RC)
within six full calendar months of receipt ensures any deficiencies are adequately
addressed in a timely manner. If the Corrective Action Plan requires that a functional
change be made to a RAS, the RAS‐owner(s) will need to submit information identified in
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PRC‐012‐2 – Remedial Action Schemes
Attachment 1 to the RC(s) for review prior to placing RAS modifications in service per
Requirement 1.
R5.
Within six full calendar months of being notified of a deficiency in its RAS based on
the evaluation performed pursuant to Requirement R4, each RAS‐owner shall submit
a Corrective Action Plan to its reviewing Reliability Coordinator(s). [Violation Risk
Factor:] [Time Horizon:]
M5. Acceptable evidence is a date‐stamped Corrective Action Plan and date‐stamped
communications with each reviewing Reliability Coordinator in accordance with
Requirement R5.
Rationale for Requirement R6: The correct operation of a RAS is important to
maintaining the reliability and integrity of the Bulk Electric System (BES). Any incorrect
operation of a RAS indicates the RAS effectiveness and/or coordination has been
compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected should be analyzed. The 120 calendar day time frame aligns with the time frame
established in Requirement R1 from PRC‐004‐4 regarding the investigation of a Protection
System Misoperation.
R6.
Within 120‐calendar days of each RAS operation or each failure of a RAS to operate,
each RAS‐owner(s) shall analyze the RAS for performance deficiencies. The analysis
shall determine whether the: [Violation Risk Factor:] [Time Horizon:]
6.1. Power System conditions appropriately triggered the RAS.
6.2. RAS responded as designed.
6.3. RAS was effective in mitigating power System issues it was designed to address.
6.4. RAS operation resulted in any unintended or adverse power System response.
M6. Acceptable evidence may include, but is not limited to, date‐stamped documentation
detailing the RAS operational analysis in accordance with Requirement R6.
Rationale for Requirement R7: Performance deficiencies identified in the analysis
conducted by the RAS‐owner(s), pursuant to Requirement R6, are likely to pose a
reliability risk to the BES. To avoid this reliability risk, Requirement R7 mandates that the
RAS‐owner(s) submit a Corrective Action Plan that establishes the mitigation methods
and timetable to address the deficiency. Submitting the Corrective Action Plan to the
Reliability Coordinator (RC) within six full calendar months of receipt ensures any
deficiencies are adequately addressed in a timely manner. If the Corrective Action Plan
requires that a functional change be made to a RAS, the RAS‐owner(s) will need to submit
information identified in Attachment 1 to the RC(s) for review prior to placing RAS
modifications in service per Requirement 1.
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R7.
Within six full calendar months of identifying a performance deficiency in its RAS
based on the analysis performed pursuant to Requirement R6, each RAS‐owner shall
submit a Corrective Action Plan to its reviewing Reliability Coordinator(s). [Violation
Risk Factor:] [Time Horizon:]
M7. Acceptable evidence is a date‐stamped Corrective Action Plan and date‐stamped
communications with the reviewing Reliability Coordinator(s) in accordance with
Requirement R7.
Rationale for Requirement R8: Requirement R8 mandates the RAS‐owner(s) implement a
Corrective Action Plan submitted to address any identified deficiency(ies) found in
conjunction with the periodic evaluation pursuant to Requirement R4, and any identified
incorrect operation found by the analysis of an actual RAS operation pursuant to
Requirement R6. Implementing the Corrective Action Plan (CAP) submitted pursuant to
either Requirement R5 or Requirement R7 ensures that any identified deficiency(ies) or
incorrect operation(s) are addressed in a timely manner. The CAP identifies the work
(corrective actions) as well as the work schedule (the time frame within which the
corrective actions are to be taken).
R8.
For each CAP submitted pursuant to Requirement R5 and Requirement R7, each RAS‐
owner shall implement the CAP. [Violation Risk Factor:] [Time Horizon:]
M8. Acceptable evidence may include, but is not limited to, dated documentation
(electronic or hardcopy format) such as work management program records, work
orders, and maintenance records that document the implementation of a CAP in
accordance with Requirement R8.
Rationale for Requirement R9: Due to the wide variety of RAS designs and
implementations, and the potential for impacing BES reliability, it is important that
periodic functional testing of RAS is performed. A functional test provides an overall
confirmation of the RAS’s ability to operate as designed and verifies the proper operation
of the non‐Protection System (control) components of a RAS that are not addressed in
PRC‐005. Protection System components that are part of a RAS are maintained in
accordance with PRC‐005. The six calendar year interval was chosen to coincide with the
maintenance intervals of various Protection System and Automatic Reclosing components
established in PRC‐005‐3. The RAS‐owner is in the best position to determine the testing
procedure and schedule due to its overall knowledge of the RAS design, installation, and
expected operation. Periodic functional testing promotes the identification of changes in
System infrastructure that could have introduced latent failures into the RAS. Functional
testing is not synonymous with end‐to‐end testing. Each segment of a RAS should be
tested but the segments can be tested individually negating the need for complex
maintenance schedules.
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R9.
At least once every six calendar years, each RAS‐owner shall perform a functional test
of each RAS to verify the overall RAS performance and the proper operation of non‐
Protection System components. [Violation Risk Factor:] [Time Horizon:]
M9. Acceptable evidence may include, but is not limited to, date‐stamped documentation
of the functional testing.
Rationale for Requirement R10: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator’s area. The database enables the RC to provide other
entities with a reliability need the ability to attain high level information on existing RAS
that potentially impact the entities’ operational and/or planning activities. Attachment 3
lists the minimum information required for the RAS database. This information allows an
entity to evaluate the need for requesting more detailed information (e.g., modeling
information ‐ Requirement R11) from the RAS‐entity. The Reliability Coordinator (RC) is
the appropriate entity to maintain the database because the RC receives the required
database information when a new or modified RAS is submitted for review.
R10. Each Reliability Coordinator shall maintain a RAS database containing the information
in Attachment 3. [Violation Risk Factor:] [Time Horizon:]
M10. Acceptable evidence may include, but is not limited to, date‐stamped spreadsheets,
database reports, or other documentation demonstrating a RAS database was
maintained in accordance with Requirement R10.
Rationale for Requirement R11: Other registered entities may have a reliability‐related
need for modeling RAS operations and will require additional information beyond what is
listed in Attachment 3. Such information may be needed to address one or more of the
following reliability‐related needs:
Periodic RAS evaluations
Planning assessment studies
Operations planning and/or real‐time analyses
BES event analyses
Coordination of RAS among entities
Requirement R11 mandates that each RAS‐entity provide the requester with either the
detailed information required to model a RAS, or a written response specifying the basis
for denying the request. Thirty (30) calendar days is a reasonable amount of time for each
RAS‐entity to respond to a request.
R11. Within 30 calendar days of receiving a written request from a registered entity with a
reliability‐related need to model RAS operation, each RAS‐entity shall provide the
requesting entity with either the requested information or a written response
specifying the basis for denying the request. [Violation Risk Factor:] [Time Horizon:]
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M11. Acceptable evidence may include, but is not limited to, date‐stamped
communications e.g. emails, letters, or other documentation demonstrating that the
RAS‐entity either provided the information to model RAS operation or provided a
written response specifying the basis for denying the request in accordance with
Requirement R11.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The applicable entity shall keep data or evidence to show compliance with
requirements (DELETE GREEN TEXT PRIOR TO PUBLISHING) Add
requirements as appropriate for this standard. This section is only for
those requirements that do not have the default data retention. since the
last audit.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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PRC‐012‐2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
R2.
R3.
D. Regional Variances
None.
E. Associated Documents
Link to the Implementation Plan and other important associated documents. (DELETE GREEN TEXT PRIOR TO PUBLISHING) A link
should be added to the implementation plan and other important documents associated with the standard once
finalized.
Version History (DELETE GREEN TEXT PRIOR TO PUBLISHING) Note: All version histories’ content should be carried over to next
generation.
Version
Date
Action
Change Tracking
(DELETE GREEN TEXT PRIOR TO PUBLISHING)
Project #: action completed
(DELETE GREEN TEXT PRIOR TO
PUBLISHING) New, Errata, Revisions,
Addition, Interpretation, etc.
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Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important RAS information for each new or functionally
modified1 RAS that the RAS‐entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1. When a RAS has been previously reviewed, only the
proposed modifications to that RAS require review; however, it will be helpful to the reviewers
if the RAS entity provides a summary of the previously approved functionality.
I.
General
Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
II.
The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012, Requirements R5 and R7]
Functional Description and Transmission Planning Information
Contingencies and system conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
A summary of technical studies, if applicable, demonstrating that the proposed RAS actions
satisfy System performance objectives for the scope of System events and conditions that
the RAS is intended to remedy. The technical studies should include information such as the
study year(s), system conditions, and contingencies analyzed on which the RAS design is
based, and when those technical studies were performed.
[Reference NERC Reliability Standard PRC‐014, R3.2]
Information regarding any future system plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
Documentation showing that inadvertent operation of the RAS satisfies the same
performance requirements as those required for the contingency for which it was designed.
For RAS that are installed for conditions or contingencies for which there are no applicable
System performance requirements, demonstrate that the inadvertent operation satisfies
the System performance requirements of Table 1, Category P7 of NERC Reliability Standard
TPL‐001‐4 or its successor.
[Reference NERC Reliability Standard PRC‐012, R1.4]
1Functionally Modified:
Any modification to a RAS beyond the replacement of components that preserve the original functionality is a functional
modification.
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Attachments
An evaluation indicating that the RAS avoids adverse interactions with other RAS, and
protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
Identification of other affected RCs.
III. Implementation
Documentation describing the equipment used for detection, telecommunications, transfer
trip, logic processing, and monitoring, whichever are applicable.
Information on detection logic and settings/parameters that control the operation of the
RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
Documentation showing that any multifunction device used to perform RAS function(s), in
addition to other functions such as protective relaying or SCADA, does not compromise the
reliability of the RAS when the device is not in service or is being maintained.
Documentation showing that an appropriate level of redundancy is provided such that a
single RAS component failure, when the RAS is intended to operate, does not prevent the
interconnected transmission system from meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its successor) as those required for the System
events and conditions for which the RAS was designed. The documentation should describe
or illustrate how the implementation design achieves this objective.
[Reference NERC Reliability Standard PRC‐012, R1.3]
Documentation describing the functional testing process.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be retired
that the RAS‐entity shall document and provide to the Reliability Coordinator for review
pursuant to Requirement R1.
Information necessary to ensure that the Reliability Coordinator is able to understand the
physical and electrical location of the RAS and related facilities.
A summary of technical studies, if applicable, upon which the decision to retire the RAS is
based.
Anticipated date of RAS retirement.
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies important reliability related considerations for the Reliability
Coordinator to review and verify for each new or functionally modified2 RAS. The RC review is
not limited to the checklist items and the RC may request additional information on any
reliability issue related to the RAS.
Determination of Review Level
RAS can have varying impacts on the power System. RAS with more significant impact require a
higher level of review than those having a lesser impact. The level of review by the RC may be
limited if the System response for a failure of the RAS to operate or inadvertent operation of
the RAS could not result in any of the following conditions:
frequency‐related instability
unplanned tripping of load or generation
uncontrolled separation or cascading outages
If any of the conditions above may be produced, the entire review checklist below should be
followed.
RAS retirement reviews may use an abbreviated format that concentrates on the Planning
justifications describing why the RAS is no longer needed. Implementation issues will seldom
require removal review.
DESIGN
The RAS actions satisfy System performance objectives for the scope of System events
and conditions that the RAS is intended to mitigate.
The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
The RAS avoids adverse interactions with other RAS, protection systems, control
systems, and operating procedures.
The effects of RAS incorrect operation, including inadvertent operation and failure to
operate (if non‐operation for RAS single component failure is acceptable), have been
identified.
The inadvertent operation of the RAS satisfies the same performance requirements as
those required for the contingency for which it was designed. For RAS that are installed
for conditions or contingencies for which there are no applicable System performance
requirements, the inadvertent operation satisfies the System performance
requirements of Table 1, Category P7 of NERC Reliability Standard TPL‐001‐4 or its
successor.
2
Functionally Modified:
Any modification to a RAS beyond the replacement of components that preserve the original functionality is a
functional modification.
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Attachments
The effects of future System plans on the design and operation of the RAS, where
applicable, have been identified.
IMPLEMENTATION
The implementation of RAS logic appropriately correlates desired actions (outputs) with
System events and conditions (inputs).
The timing of RAS actions is appropriate to its System performance objectives.
A single component failure in a RAS does not prevent the BES from meeting the same
performance requirements as those required for the System events and conditions for
which the RAS was designed.
The RAS design facilitates periodic testing and maintenance.
The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the System conditions and
events for which it is designed to operate.
RAS automatic arming, if applicable, has the same degree of redundancy as the RAS
itself.
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Attachments
Attachment 3
Database Information
1. RAS name
2. RAS‐entity and contact information
3. Expected or actual in‐service date; most recent (Requirement R2) review date; 5‐year
(Requirement R4) evaluation date; and, date of retirement, if applicable
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery)
5. Description of the contingencies or System conditions for which the RAS was designed
(initiating conditions)
6. Corrective action taken by the RAS
7. Any additional explanation relevant to high level understanding of the RAS
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Supplemental Material
Requirement R1:
Each Remedial Action Scheme (RAS) is unique and its action(s) can have a significant impact on
the reliability and integrity of the Bulk Electric System (BES); therefore, a review of a proposed
new RAS or an existing RAS proposed for functional modification or retirement (removal from
service) must be completed prior to implementation. A functional modification is any
modification to a RAS beyond the replacement of components that preserves the original
functionality.To facilitate a review that promotes reliability, the RAS‐entity must provide the
reviewer with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and Requirement R1
mandates the RAS‐entity provide them to the reviewing Reliability Coordinator (RC). The RC
responsible for the review will be the RC that coordinates the area where the RAS is located. In
cases where a RAS crosses multiple RC Area boundaries, each affected RC would be responsible
for conducting either individual reviews or a coordinated review.
Requirement R2:
Requirement R2 mandates that the Reliability Coordinator (RC) perform a review of a proposed
new RAS or an existing RAS proposed for functional modification or retirement (removal from
service) in its RC area.
The RC is the functional entity best‐suited to perform the RAS reviews because it has a wide‐
area perspective of reliability that includes awareness of reliability issues in its neighboring RC
Areas. This wide‐area purview provides continuity in the review process and better facilitates
the coordination of interactions among separate RAS as well as the coordination of interactions
among RAS and other protection and control systems. The selection of the RC also minimizes
the possibility of a “conflict of interest” that could exist because of business relationships
among the RAS‐Entity, Planning Coordinator (PC), Transmission Planner (TP), or other entity
that could be involved in the planning or implementation of a RAS. The RC may designate a
third party to conduct the RAS reviews; however, the RC will retain the responsibility of
compliance with this requirement.
Attachment 2 of this standard is a checklist provided to the RC to assist in identifying important
design and implementation aspects of RAS, and in facilitating consistent reviews for each RAS
submitted. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the Region(s) in which it is
located
Requirement R3:
Requirement R3 mandates the RAS‐entity address all reliability‐related issues identified by the
Reliability Coordinator (RC) during the RAS review, and obtain approval from the RC that the
RAS implementation can proceed. This interaction promotes reliability by minimizing the
introduction of inadvertent actions (risks) to the BES. A specific time period for the RAS‐entity
to respond to the RC’s review is not necessary because an expeditious response is in the self‐
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Supplemental Material
interest of the RAS‐owner(s) to effect a timely implementation. The review by the RC is
intended to identify reliability issues that must be resolved before the RAS can be put in service.
The reliability issues could involve dependability, security, or both.
Dependability is a component of reliability and is the measure of a device’s certainty to operate
when required. Since RAS are usually installed to meet performance requirements of NERC
standards, a failure of the RAS to operate when intended would put the System at risk of
violating NERC performance standards if the critical contingency(ies) or System conditions
occur. This risk is usually mitigated by installing an appropriate level of redundancy as part of
the RAS so that it will still accomplish its intended purpose even while experiencing a single
component failure.
Security is a component of reliability and is the measure of a device’s certainty not to operate
falsely. False, or inadvertent operation of a RAS results in taking some programmed action that
the RAS would take for a correct operation, but without either the appropriate arming
conditions or occurrence of the critical contingency(ies) or System conditions expected to
trigger the RAS action. Typically these actions include shedding load or generation or re‐
configuring the System. This inadvertent action is undesirable in the absence of the critical
System conditions and may, on its own, put the System in a less secure state. The standard
allows an impact up to the level that would occur for a correct operation. If this risk needs to be
further mitigated, voting schemes have been successfully used in the industry for both RAS and
Protection systems.
Either type of reliability issue must be resolved before placing the RAS in service to avoid
placing the System at unacceptable risk. The RAS‐entity (and any other RAS‐owner) or the RC
may have alternative ideas or methods available to resolve the issue(s). In either case, the
concern needs to be resolved in favor of reliability, and the RC has the final decision.
Requirement R4:
Requirement R4 mandates that a technical evaluation of each RAS be performed at least once
every 60 full calendar months. The purpose of periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as BES performance following an inadvertent
RAS operation. This periodic evaluation is needed due to possible changes in system topology
and operating conditions that may have occurred since the previous RAS evaluation (or initial
review) was completed. Sixty (60) full calendar months was selected as the maximum time
frame for the evaluation based on the time frames for similar requirements in Reliability
Standards PRC‐006‐1, PRC‐010‐1, and PRC‐014‐1. The RAS evaluation can be performed sooner
if it is determined that material changes to system topology or system operating conditions that
could potentially impact the effectiveness or coordination of the RAS have occurred since the
previous RAS evaluation or will occur before the next scheduled evaluation. The periodic RAS
evaluation will typically lead to one of the following outcomes: 1) affirmation that the existing
RAS is adequate; 2) identification of changes needed to the existing RAS; or, 3) justification for
RAS retirement.
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Supplemental Material
The items required to be addressed in the evaluations (Parts 4.1, 4.2, 4.3) are planning analyses
which involve modeling of the interconnected transmission system; consequently, the
Transmission Planner (TP) is the functional entity best qualified to perform the analyses. To
promote reliability, the TP is required to provide the RAS‐owner(s) and the Reliability
Coordinator(s) with the results of each evaluation.
Part 4.3 requires that the inadvertent operation of the RAS meet the same requirements as
those required for the contingency(ies) or System conditions for which it was installed. So if the
RAS was designed to meet one of the Planning Events (P0‐P7) in TPL‐001‐4, then the
inadvertent operation of the RAS must meet the same performance requirements listed in the
standard for that planning event. Part 4.3 also requires that the inadvertent operation of the
RAS installed for an Extreme Event in TPL‐001‐4 or for some other contingency or System
condition not defined in TPL‐001‐4 (therefore without performance requirements), meet the
minimum System performance requirements of Category P7 in Table 1 of NERC Reliability
Standard TPL‐001‐4, or its successor. These would include requirements such as the System
shall remain stable, cascading and uncontrolled islanding shall not occur, applicable Facility
Ratings shall not be exceeded, System steady state voltages and post‐Contingency voltage
deviations shall be within acceptable limits, transient voltage responses shall be within
acceptable limits.
Requirement R5:
Deficiencies identified in the periodic RAS evaluation conducted by the Transmission Planner in
Requirement R4 are likely to pose a reliability risk to the BES due to the impact of either a RAS
operation or incorrect operation. To avoid this reliability risk, Requirement R5 mandates that
the RAS‐owner(s) submit a Corrective Action Plan that establishes the mitigation methods and
timetable to address the deficiency. Submitting the Corrective Action Plan to the Reliability
Coordinator (RC) within six full calendar months of receipt ensures any deficiencies are
adequately addressed in a timely manner. If the Corrective Action Plan requires that a
functional change be made to a RAS, the RAS‐owner(s) will need to submit information
identified in Attachment 1 to the RC(s) for review prior to placing RAS modifications in service
per Requirement 1.
Requirement R6:
The correct operation of a RAS is important to maintaining the reliability and integrity of the
Bulk Electric System (BES). Any incorrect operation of a RAS indicates the RAS effectiveness
and/or coordination has been compromised. Therefore, all operations of a RAS and failures of a
RAS to operate when expected should be analyzed. The purpose of the analysis is to determine
whether the RAS operation was appropriately triggered; whether the RAS functioned as
designed; whether the RAS actions were effective in producing the intended System response;
and whether the RAS operation or non‐operation resulted in any unintended or adverse System
response. The 120 calendar day time frame aligns with the time frame established in
Requirement R1 from PRC‐004‐4 regarding the investigation of a Protection System
Misoperation.
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Requirement R7:
Performance deficiencies identified in the analysis conducted by the RAS‐owner(s), pursuant to
Requirement R6, are likely to pose a reliability risk to the BES. To avoid this reliability risk,
Requirement R7 mandates that the RAS‐owner(s) submit a Corrective Action Plan that
establishes the mitigation methods and timetable to address the deficiency. Submitting the
Corrective Action Plan to the Reliability Coordinator (RC) within six full calendar months of
receipt ensures any deficiencies are adequately addressed in a timely manner. If the Corrective
Action Plan requires that a functional change be made to a RAS, the RAS‐owner(s) will need to
submit information identified in Attachment 1 to the RC(s) for review prior to placing RAS
modifications in service per Requirement 1.
Requirement R8:
Requirement R8 mandates the RAS‐owner(s) implement a Corrective Action Plan submitted to
address any identified deficiency(ies) found in conjunction with the periodic evaluation
pursuant to Requirement R4, and any identified incorrect operation found by the analysis of an
actual RAS operation pursuant to Requirement R6. Implementing the Corrective Action Plan
(CAP) submitted pursuant to either Requirement R5 or Requirement R7 ensures that any
identified deficiency(ies) or incorrect operation(s) are addressed in a timely manner. The CAP
identifies the work (corrective actions) as well as the work schedule (the time frame within
which the corrective actions are to be taken).
A Corrective Action Plan (CAP) documents a RAS performance deficiency, the strategy to correct
the deficiency with identified tasks, the responsible party assigned to each task, and the
targeted completion date(s).
The following are examples situations of when a CAP is required:
a) A determination after a RAS operation/non‐operation investigation that the RAS did
not meet performance expectations. The RAS did not operate as designed.
b) Periodic planning assessment reveals RAS changes are necessary to satisfy
performance effectiveness or to correct identified coordination issues.
c) Equipment failure detrimentally affects the dependability or security of the RAS.
Requirement R9:
The reliability objective of Requirement R9 is to test the non‐Protection System components of
a RAS (controllers such as PLCs) and to verify the overall performance of the RAS through
functional testing. Functional tests validate RAS operation by ensuring system states are
detected and processed, and that actions taken by the controls are correct and within the
expected time frames using the in‐service settings and logic.
Functional testing can be difficult to schedule and perform, but it is critical to ensure the proper
functioning of RAS and the resulting BES reliability. Since the functional test operates the RAS
under controlled conditions with known System states and expected results, testing and result
analysis can be performed without impact to the BES. The RAS‐owner is in the best position to
determine the testing procedure and schedule due to their overall knowledge of the RAS
design, installation, and expected operation. Periodic functional testing provides the RAS‐owner
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assurance that latent failures are not present in the RAS design and implementation, and also
promotes identification of changes in System infrastructure could have introduced latent
failures. The six calendar year interval was chosen to coincide with the maintenance intervals of
various Protection System and Automatic Reclosing components established in PRC‐005‐3.
Functional testing is not synonymous with end‐to‐end testing. Each segment of a RAS should be
tested but the segments can be tested individually negating the need for complex maintenance
schedules. If System conditions do not allow a complete end‐to‐end system test or a RAS is
implemented across many locations and uses a wide variety of components, functional testing
of small zones within a larger RAS, such that all controls in overlapping zones are tested over
time constitute an acceptable functional testing approach. The goal of the functional test
procedure is inclusion of all conditions the RAS uses for detection, arming, operating, and data
collection that will address the System condition(s) for which the RAS is designed.
As an example, consider a RAS implemented using one control component not addressed in the
Protection System definition but used regularly in RAS: a programmable logic controller (PLC).
The PLC does not meet the definition of a Protection System and will have no required
maintenance as part of PRC‐005. In this simplified example, the PLC based RAS is sensing
System conditions such as loading and line status from many locations, and implements breaker
tripping at multiple locations to alleviate an overload condition. At one of these locations, a line
protective relay, included in a RAS‐owner’s Protection System Maintenance Plan as a Protection
System component, is used to operate a breaker upon receipt an operate command from the
remote RAS PLC. The relay sends data and receives commands from the RAS PLC over non‐
Protection System communications infrastructure. A functional test would simulate via external
signals to the PLC system conditions requiring an operate command to the protective relay,
operating its associated breaker. This action verifies RAS action, verifies PLC control logic, and
verifies the RAS communications from the PLC to the relay. To complete this portion of a
functional test, application of external testing signals to the protective relay, verified at the PLC
are necessary to confirm full functioning of the RAS zone being tested. In this example the RAS
is implemented across several locations, and the testing described would only constitute one
zone of a full RAS functional test. The remaining zones based on the RAS design would also
require testing.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” section 8 (particularly 8.3‐8.5),
provides a very good overview of functional testing. The following opens section 8.3:
“Proper implementation requires a well‐defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component‐level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
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The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of contingencies, and to verify scheme performance as well as the inputs and outputs.”
Requirement R10:
The RAS database is a comprehensive record of all RAS existing in a Reliability Coordinator’s
area. The database enables the RC to provide other entities with a reliability need the ability to
attain high level information on existing RAS that potentially impact the entities’ operational
and/or planning activities. Attachment 3 lists the minimum information required for the RAS
database. This information allows an entity to evaluate the need for requesting more detailed
information (e.g., modeling information ‐ Requirement R11) from the RAS‐entity. The Reliability
Coordinator (RC) is the appropriate entity to maintain the database because the RC receives the
required database information when a new or modified RAS is submitted for review.
Requirement R11:
Other registered entities may have a reliability‐related need for modeling RAS operations and
will require additional information beyond what is listed in Attachment 3. Such information
may be needed to address one or more of the following reliability‐related needs:
Periodic RAS evaluations
Planning assessment studies
Operations planning and/or real‐time analyses
BES event analyses
Coordination of RAS among entities
Requirement R11 mandates that each RAS‐entity provide the requester with either the detailed
information required to model a RAS, or a written response specifying the basis for denying the
request. Thirty (30) calendar days is a reasonable amount of time for each RAS‐entity to
respond to a request.
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a remedial action
scheme (RAS) it is necessary for the RAS owner(s) to provide a detailed list of information
describing the RAS to the reviewing Reliability Coordinator (RC). While information may be
needed from all owners of a RAS, a single RAS‐owner (designated as the (RAS‐entity)) is usually
assigned the responsibility of compiling the RAS data and presenting it to the RC(s) review
team. Other RAS‐owners may participate in the review, if they choose.
The necessary data ranges from a general overview of the scheme to results of Transmission
Planning studies that illustrate System performance before and after the RAS goes into service,
as well as expected performance for unusual conditions, and whether certain adverse reliability
impacts may occur. Possible adverse interactions, i.e. coordination between the RAS and other
RAS and protection and control systems will be examined. This review can include wide ranging
electrical design issues involving the specific hardware, logic, telecommunications and other
relevant equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified3 RAS that the RAS‐entity shall document and provide to the Reliability Coordinator
(RC) for review pursuant to Requirement R1. When a RAS has been previously reviewed, only
the proposed modifications to that RAS require review; however, it will be helpful to the
reviewers if the RAS entity provides a summary of the previously approved RAS functionality.
I.
General
Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
o Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See “RAS Design”, below, for
additional information.
o Provide a single line drawing(s) showing all sites involved. The drawing(s) should
provide sufficient information to allow the RC review team to assess design
reliability, and should include information such as the bus arrangement, circuit
breakers, the associated switches, etc. For each site, indicate whether detection,
logic, action, or a combination of these is present.
Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3Functionally Modified:
Any modification to a RAS beyond the replacement of components that preserve the original functionality is a functional
modification.
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II.
The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012‐2, Requirements R5 and R7]
o The CAP is required if the periodic evaluation pursuant to Requirement R4, or the
analysis of an actual RAS operation pursuant to Requirement R6 identified any
performance deficieny(ies).
Functional Description and Transmission Planning Information
Contingencies and system conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
o The System conditions which would result if no RAS action occurred should be
identified.
o Include a description of the System conditions which should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical system
contingencies or other operating conditions when RAS action is intended to occur. If
no arming conditions are required, this should also be stated.
o Event based RAS are triggered by specific contingencies that initiate mitigating
action. These contingencies should be identified. Condition based RAS may also be
initiated by specific contingencies, but this is not always required.
The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
o Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup”
mitigating measures that may be required in case of a single RAS component failure.
A summary of technical studies, if applicable, demonstrating that the proposed RAS actions
satisfy System performance objectives for the scope of System events and conditions that
the RAS is intended to remedy. The technical studies should include information such as the
study year(s), system conditions, and contingencies analyzed on which the RAS design is
based, and when those technical studies were performed.
[Reference NEC Reliability Standard PRC-014, R3.2]
o Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements.
Information regarding any future system plans that will impact the RAS.
[Reference NERC Reliability Standard PRC-014, R3.2]
o The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to
be aware of any longer range Plans that may have an impact on the proposed RAS.
Such knowledge of future Plans is helpful to provide perspective on the capabilities
of the RAS.
Documentation showing that inadvertent operation of the RAS satisfies the same
performance requirements as those required for the contingency for which it was designed
or, if no performance requirements apply, the inadvertent operation of the RAS satisfies the
requirements of Category P7 in Table 1 of NERC Reliability Standard TPL‐001‐4, or its
successor.
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[Reference NERC Reliability Standard PRC‐012, R1.4]
An evaluation indicating that the RAS avoids adverse interactions with other RAS, and
protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
o RAS are complex schemes that typically take action which trips load or generation or
re‐configures the system. Many RAS depend on sensing specific system
configurations to determine whether they need to arm or take actions. Examples
include: overlapping actions among RAS that may have the potential to result in
cascading, unless coordinated, RAS that reconfigure the System also change the
available fault duty, which can affect distance relay overcurrent (“fault detector”)
supervision and ground overcurrent protection coordination.
Identification of other affected RCs.
o This information is needed to aid in information exchange among all affected
entities and coordination of the RAS with other RAS and protection and control
systems.
III.
Implementation
Documentation describing the equipment used for detection, telecommunications, transfer
trip, logic processing, and monitoring, whichever are applicable.
Logic Processing
o All RAS require some form of logic processing to determine the action to take when
the scheme is triggered. Required actions are always scheme dependent. Different
actions may be required at different arming levels or for different contingencies.
Scheme logic may be achievable by something as simple as wiring a few auxiliary relay
contacts or by much more complex logic processing.
o Platforms that have been used reliably and successfully, include programmable logic
controllers (PLCs) in various forms, personal computers (PCs), microprocessor
protective relays, remote terminal units (RTUs), and logic processors. Single‐function
relays have been used historically to implement RAS, but this approach is now less
common except for very simple new RAS or minor additions to existing RAS.
Communications Channels
o Communication channels used for sending and receiving RAS information between
sites and/or transfer trip devices must meet at least the same criteria as for other
relaying protection communication channels. Discuss performance of any non‐
deterministic communication systems used (such as Ethernet).
o The scheme logic should be designed so that loss of the channel, noise, or other
channel failure will not result in a false operation of the scheme.
o It is highly desirable that the channel equipment and communications media (power
line carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS
owner, or perhaps leased from another entity familiar with the necessary reliability
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requirements. All channel equipment must be monitored and alarmed to the dispatch
center so that timely diagnostic and repair action shall be taken place upon failure.
o Communication channels shall be well labeled or identified so that the personnel
working on the channel can readily identify the proper circuit. Channels between
entities shall be identified with a common name at all terminals.
Information on detection logic and settings/parameters that control the operation of the
RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
Detection and initiating devices must be designed to be as secure as possible. The
following discussion identifies several types of devices that have been used as disturbance
detectors:
Line open status (event detectors),
Protective relay inputs and outputs (event and parameter detectors),
Transducer and IED (analog) inputs (parameter and response detectors),
Rate of change (parameter and response detectors).
Several methods to determine line open status are in common use, often in combination:
Auxiliary switch contacts from circuit breakers and disconnect switches (52b, 89b),
Undercurrent detection (a low level indicates an outage),
Breaker trip bus monitoring, and
Other detectors such as angle, voltage, power, frequency, rate of change of these, out
of step, etc.
Documentation showing that any device used to perform RAS function(s), in addition to
other functions such as protective relaying or SCADA, does not compromise the reliability of
the RAS when the device is not in service or is being maintained.
o In this context, a multifunction device (e.g. microprocessor‐based relay) is a single
device that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the
device is in service or when is being maintained. The following list outlines concerns
to be addressed when the RAS function is applied in the same microprocessor‐based
relay as the protection function:
a) Describe how the multifunction device is applied in the RAS.
b) Show the general arrangement and describe how the multi‐function
device is labeled in the design and application, so as to identify the RAS and
other device functions.
c) Describe the procedures used to isolate the RAS function from other
functions in the device.
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d) Describe the procedures used when each multifunction device is removed
from service and whether any other coordination with other protection is
required.
e) Describe how each multifunction device is tested, both for commissioning
and during periodic maintenance testing, with regard to each function of the
device.
f) Describe how overall periodic RAS functional and throughput tests are
performed if multifunction devices are used for both local protection and
RAS.
g) Describe how upgrades to the multifunction device, such as firmware
upgrades, are accomplished. How is the RAS function taken into
consideration?
o Other devices usually not considered multifunction devices such as auxiliary relays,
control switches, and instrument transformers may serve multiple purposes such as
protection and RAS. Similar concerns apply for these applications as noted above.
Documentation showing that a single component failure in a RAS does not prevent the BES
from meeting the same performance requirements as those required for the System events
and conditions for which the RAS was designed. The documentation should describe or
illustrate how the implementation design achieves this objective.
[Reference NERC Reliability Standard PRC‐012, R1.3]
The critical part of PRC‐012 R1.3 philosophy is that a RAS should be designed so that a “single
[RAS] component failure … does not prevent … meeting the performance requirements defined
in Reliability Standards”. The philosophy regarding “single component failure” from PRC‐012‐0
is carried over in to this standard. Redundancy is one way to implement the “single component
failure” philosophy but other methods are acceptable.
The following list are examples of RAS components that could be considered in the single
component failure analysis:
Any single ac secondary current or voltage source and/or related inputs to the RAS.
Any single device used to measure electrical quantities used by the RAS.
Any single communication channel and/or any single piece of related communication
equipment used by the RAS.
Any single computer or programmable logic device used to analyze information and
provide RAS operational output.
Any single element of the dc control circuitry that is used for the RAS, including breaker
closing circuits.
Any single auxiliary relay or auxiliary device used by the RAS.
Any single breaker trip coil for any breaker operated by the RAS.
Any single station battery or single charger, or other single dc source, where central
monitoring is not provided for both low voltage and battery open conditions.
Duplication of the listed components is a way to achieve redundancy and meet the “single
component failure” requirement. For schemes performing distributed actions (e.g. load
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shedding or generation rejection at multiple locations), over arming (providing extra corrective
action to cover failure to operate of one critical component) can also be an effective option, as
long as it does not compromise the performance of the system. Other coordinated Protection
Systems, such as breaker failure, may be used as long as the System performance resulting
from breaker failure is still acceptable under the original contingency the RAS was designed to
mitigate
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be retired
that the RAS‐entity shall document and provide to the Reliability Coordinator for review
pursuant to Requirement R1.
Information necessary to ensure that the Reliability Coordinator is able to understand the
physical and electrical location of the RAS and related facilities.
A summary of technical studies, if applicable, upon which the decision to retire the RAS is
based.
Anticipated date of RAS retirement.
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Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information the RC must consolidate into its database
for each RAS in its area.
1. RAS name
o The usual name used to identify the RAS.
2. RAS‐entity and contact information
o A reliable phone number or email address should be included to contact the RAS‐
entity if more information is needed (e.g. modeling information per requirement
R11). At a minimum, the name of the RAS‐entity responsible for the RAS
information.
3. Expected or actual in‐service date; most recent (Requirement R2) review date; 5‐year
(Requirement R4) evaluation date; and, date of retirement, if applicable
o Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery)
o A short description of the reason for installing the RAS is sufficient, as long as the
main system issues addressed by the RAS can be identify by someone with a
reliablilty need.
5. Description of the contingencies or System conditions for which the RAS was designed
(initiating conditions)
o A high level summary of the conditions/contingencies is expected. Not all
combinations of conditions are required to be listed.
6. Corrective action taken by the RAS
o For schemes shedding load or generation, the maximum amount of MW should be
included.
7. Any additional explanation relevant to high level understanding of the RAS
o If deemed necessary, any additional information can be included in this section, but
is not mandatory.
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Unofficial Comment Form
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
PRC-012-2
DO NOT use this form for submitting comments. Use the electronic form to submit comments on draft 1
of PRC-012-2 – Remedial Action Schemes. The electronic comment form must be submitted by 8 p.m.
Eastern, Wednesday, May 20, 2015.
For this informal posting, the drafting team is soliciting stakeholder feedback on the scope and work
product developed thus far. The drafting team will use the informal feedback to finalize the preliminary
draft of PRC-012-2. Stakeholders may communicate additional feedback directly to the drafting team
through its open meetings leading up to the first formal posting. The next meeting is scheduled for June 811, 2015. Meeting details will be posted to the NERC calendar early May 2015.
Documents and information about this project are available on the project page. If you have questions,
contact Standards Developer, Al McMeekin (via email), or at (404) 446-9675.
Background Information
This project is addressing all aspects of Remedial Action Schemes (RAS) and Special Protection Systems
(SPS) contained in the RAS/SPS-related Reliability Standards: PRC-012-1, PRC-013-1, PRC-014-1, PRC-0151, and PRC-016-1. The maintenance of the Protection System components associated with RAS (PRC-0171 Remedial Action Scheme Maintenance and Testing) are already addressed in PRC-005-2. PRC-012-2
addresses the testing of the non-Protection System components associated with RAS/SPS.
In FERC Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and
PRC-014-0 as “fill-in-the-blank” standards and did not approve or remand them because they are
applicable to the Regional Reliability Organizations (RROs), assigning the RROs the responsibility to
establish regional procedures and databases, and to assess and document the operation, coordination,
and compliance of RAS/SPS. The deference to regional practices precludes the consistent application of
RAS/SPS-related Reliability Standard requirements.
The proposed draft of PRC-012-2 corrects the applicability of the fill-in-the-blank standards by assigning
the requirement responsibilities to the specific users, owners, and operators of the Bulk-Power System;
and incorporates the reliability objectives of all the RAS/SPS-related standards.
Questions
Requirements R1, R2, and R3 pertain to the submittal of Attachment 1 information to the Reliability
Coordinator (RC) for the review of RAS, the RC using Attachment 2 as a guide for performing the RAS
review, and the RC approving the RAS prior to the RAS being placed in-service. Questions 1-4 are relevant
for these activities.
1. RAS review and approval: Do you agree that RAS should be reviewed and approved by an
independent party prior to placing the RAS in-service? If no, please state the basis for your
disagreement and an alternative approach.
Yes
No
Comments:
2. Information listed in Attachment 1: Do you agree that the RAS information required in Attachment 1
is a comprehensive list? If no, please identify what other information you think is necessary for a
thorough RAS review.
Yes
No
Comments:
3. Choice of Reliability Coordinator (RC): Do you agree with the RC being the functional entity
designated to review the RAS? If no, please provide the basis for your disagreement, your choice of
functional entity to conduct the reviews, and the rationale for your choice.
Yes
No
Comments:
4. Checklist in Attachment 2: Do you agree that the checklist in Attachment 2 provides a comprehensive
guide for the RC to facilitate a thorough RAS review? If no, please identify what other reliabilityrelated considerations should be included in Attachment 2 and the rationale for your choice.
Yes
No
Comments:
Requirement R4 mandates the Transmission Planner perform a technical evaluation (planning analyses) of
each RAS at least once every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an inadvertent operation of the RAS.
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The drafting team considered the RAS classification systems used by several Regions to be rooted in PRC012, Requirement R1, R1.4. which reads: “Requirements to demonstrate that the inadvertent operation of
a RAS shall meet the same performance requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was designed, and not exceed TPL-003-0.” Although, the drafting
team is not proposing to use formal RAS classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
Questions 5 and 6 pertain to these topics.
5. Choice of Transmission Planner (TP): Do you agree with the TP being the functional entity designated
to evaluate the RAS? If no, please provide the basis for your disagreement, your choice of functional
entity to conduct the evaluations, and the rationale for your choice.
Yes
No
Comments:
6. No RAS Classification: Do you agree that the language of Requirement R4, its Parts, and Attachment 1
accomplish the objectives of RAS “classification” without having a formal RAS classification system in
the standard? If no, please provide the basis for your disagreement and describe an alternate
proposal.
Yes
No
Comments:
Requirement R6 mandates each RAS-owner analyze each RAS operation or failure of a RAS to operate to
identify performance deficiencies. Question 7 pertains to Requirement R6.
7. RAS Operational Analyses: Do you agree that the application of Requirement R6 and its Parts would
identify performance deficiencies in RAS? If no, please provide the basis for your disagreement and an
alternate proposal.
Yes
No
Comments:
Requirements R5 and R7 pertain to the submittal of Corrective Action Plans (CAPs) to the Reliability
Coordinator (RC) for review, and Requirement R8 mandates the implementation of each CAP. Question 8
addresses these requirements.
Unofficial Comment Form | Project 2010-05.3 Phase 3 of Protection Systems: RAS
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8. Corrective Action Plans: Do you agree that the application of Requirements R5, R7, and R8 would
address the reliability objectives associated with CAPs? If no, please provide the basis for your
disagreement and describe an alternate proposal.
Yes
No
Comments:
Requirement R9 mandates each RAS-owner periodically perform a functional test of each RAS to verify
the overall RAS performance and the proper operation of non-Protection System components. Question 9
pertains to Requirement R9.
9. Functional Testing of RAS: Do you agree that functional testing of each RAS would verify the overall
RAS performance and the proper operation of non-Protection System components? If no, please
provide the basis for your disagreement and describe an alternate proposal.
Yes
No
Comments:
Requirements R10 and R11 pertain to the RAS database, Attachment 3, and the sharing of RAS
information for reliability-related needs. Questions 10 11, 12, and 13 pertain to these topics.
10. Choice of Reliability Coordinator (RC): Do you agree with the RC being the functional entity
designated to maintain the RAS database in Requirement R10? If no, please provide the basis for your
disagreement, your choice of functional entity, and the rationale for your choice.
Yes
No
Comments:
11. Information listed in Attachment 3: Do you agree that the RAS information required in Attachment 3
(Requirement R10) provides the RC with enough detail of each RAS to meet its reliability-related
needs? If no, please identify what other reliability-related information should be included in
Attachment 3 and the rationale for your choice.
Yes
No
Comments:
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12. Requirement R11: Do you agree that there a reliability benefit to Requirement R11? Please provide
the rationale for your answer.
Yes
No
Comments:
13. Choice of RAS-entity: Do you agree with the RAS-entity being the entity designated to provide the
detailed RAS information to other registered entities with a reliability-related need in Requirement
R11? If no, please provide the basis for your disagreement, your choice of entity, and the rationale for
your choice.
Yes
No
Comments:
14. If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Comments:
Unofficial Comment Form | Project 2010-05.3 Phase 3 of Protection Systems: RAS
PRC-012-2 Draft 1 | April 2015
5
Special Protection Systems (SPS)
and Remedial Action Schemes (RAS):
Assessment of Definition, Regional
Practices, and Application of Related
Standards
Revision 0.1 – April 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
404-446-2560
| www.nerc.com
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NERC’s Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory authority established to enhance
the reliability of the bulk power system in North America. NERC develops and enforces Reliability Standards; assesses
adequacy annually via a ten-year forecast and winter and summer forecasts; monitors the bulk power system; and
educates, trains, and certifies industry personnel. NERC is the electric reliability organization for North America, subject to
1
oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.
NERC assesses and reports on the reliability and adequacy of the North American bulk power system, which is divided into
eight Regional areas, as shown on the map and table below. The users, owners, and operators of the bulk power system
within these areas account for virtually all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte,
México.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce
Reliability Standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those
standards mandatory and enforceable. In Canada, NERC presently has memorandums of understanding in place with
provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the Canadian National
Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law.
NERC has an agreement with Manitoba Hydro making reliability standards mandatory for that entity, and Manitoba has
recently adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators
in the province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s
Transportation Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending.
NERC and NPCC have been recognized as standards-setting bodies by the Régie de l’énergie of Québec, and Québec has the
framework in place for reliability standards to become mandatory. NERC’s reliability standards are also mandatory in Nova
Scotia and British Columbia. NERC is working with the other governmental authorities in Canada to achieve equivalent
recognition.
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Table of Contents
NERC’s Mission ............................................................................................................................................................................ 2
Table of Contents ......................................................................................................................................................................... 3
Executive Summary ..................................................................................................................................................................... 5
Introduction ................................................................................................................................................................................. 6
Problem Statement .................................................................................................................................................................. 6
Background .............................................................................................................................................................................. 6
NERC Definitions .................................................................................................................................................................. 6
NERC Reliability Standards ................................................................................................................................................... 7
Chapter 1 – SPS Definition ........................................................................................................................................................... 8
Considerations for a Revised Definition .................................................................................................................................. 8
Other Definitions in Industry ............................................................................................................................................... 8
Common Application of SPS in Industry .............................................................................................................................. 8
Classification of SPS Types ................................................................................................................................................... 9
Common Exclusions from the SPS Definition in Industry .................................................................................................. 10
Exclusion for Operator Aides ............................................................................................................................................. 11
Voltage Threshold .............................................................................................................................................................. 11
Proposed Definition ............................................................................................................................................................... 11
Definition of Significant and Limited Impact ......................................................................................................................... 13
Chapter 2 – Design and Maintenance Requirements ................................................................................................................ 14
General Design Considerations .............................................................................................................................................. 14
SPS Single Component Failure Requirements........................................................................................................................ 14
Maintenance and Testing ...................................................................................................................................................... 15
Chapter 3 – Study and Documentation Requirements .............................................................................................................. 16
Review and Approval of New or Modified SPS ...................................................................................................................... 16
Assessment of Existing SPS .................................................................................................................................................... 17
Study of SPS in Annual Transmission Planning Assessments ............................................................................................. 17
Periodic Comprehensive Assessments of SPS Coordination .............................................................................................. 17
Documentation Requirements .............................................................................................................................................. 18
Data Submittals by Entities that Own SPS ......................................................................................................................... 18
SPS Database ..................................................................................................................................................................... 19
Chapter 4 – Operational Requirements ..................................................................................................................................... 20
Monitoring of Status .............................................................................................................................................................. 20
Notification of Status ............................................................................................................................................................. 20
Response to Failures .............................................................................................................................................................. 21
Operational Documentation .................................................................................................................................................. 21
Chapter 5 – Analysis of SPS Operations ..................................................................................................................................... 22
SPS Misoperation Definition .................................................................................................................................................. 22
SPS Operation Review Process .............................................................................................................................................. 23
Chapter 6 – Recommendations ................................................................................................................................................. 25
Definition ............................................................................................................................................................................... 25
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Classification .......................................................................................................................................................................... 26
Applicability to Functional Model Entities ............................................................................................................................. 26
Revisions to Reliability Standards .......................................................................................................................................... 26
Standard PRC-012-1 – SPS Review, Assessment, and Documentation .............................................................................. 28
Standard PRC-016-1 – SPS Misoperations ......................................................................................................................... 28
Standard PRC-005-2 – Protection System Maintenance and Testing ................................................................................ 28
Recommendations to Be Included in Other Standards ..................................................................................................... 28
Appendix A – Modeling and Simulation Considerations ........................................................................................................... 29
General Considerations for Simulations ................................................................................................................................ 29
Use of SPS Simulations in Transmission Planning Studies ..................................................................................................... 31
Appendix B – Operational Considerations ................................................................................................................................. 33
Real-time SPS Evaluation ....................................................................................................................................................... 33
Multiple Decision-Making Capability ..................................................................................................................................... 33
Information Management ..................................................................................................................................................... 33
Modeling Simplicity and Usability.......................................................................................................................................... 34
Appendix C – Mapping of Requirements from Existing Standards ............................................................................................ 35
Appendix D – Standards Committee Request for Research; January 9, 2011 ........................................................................... 43
Appendix E – Scope of Work Approved by the Planning Committee; June 8, 2011 .................................................................. 44
Appendix F – System Analysis and Modeling Subcommittee Roster ......................................................................................... 45
Appendix G – System Protection and Control Subcommittee Roster ....................................................................................... 46
Appendix H – Additional Contributors ....................................................................................................................................... 47
Appendix I – Revision History .................................................................................................................................................... 48
This technical document was approved by the NERC Planning Committee on March 5, 2013.
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Executive Summary
The existing NERC Glossary of Terms definition for a Special Protection System (SPS or, as used in the Western
Interconnection, a Remedial Action Scheme or RAS) lacks clarity and specificity necessary for consistent identification and
classification of protection schemes as SPS or RAS across the eight NERC Regions, leading to inconsistent application of the
related NERC Reliability Standards. In addition, three of the related standards (PRC-012-0, PRC-013-0, and PRC-014-0) were
identified by FERC in Order No. 693 as fill-in-the-blank standards and consequently are not mandatory and enforceable.
NERC Standards Project 2010-05.2, Phase 2 of Protection Systems: SPS and RAS, will modify the current standards and
definitions related to SPS and RAS. The NERC Standards Committee has identified that prior to initiating a project to address
these issues, additional research is necessary to clearly define the problem and recommend solutions for consideration. A
request for research was submitted by the Standards Committee on January 9, 2012 (see Appendix D). The Planning
Committee had already approved a joint effort by the System Analysis and Modeling Subcommittee (SAMS) and System
2
Protection and Control Subcommittee (SPCS) on June 8, 2011 (see Appendix E) which includes issues identified in the
request for research. This report addresses all issues identified in the scope of the joint SAMS and SPCS project as well as
the Standards Committee request for research; upon approval by the Planning Committee the report should be forwarded
to the Standards Committee to support Project 2010-05.2.
This report includes recommendations for a new definition of SPS and revisions to the six SPS-related PRC standards. A
strawman definition is provided that eliminates ambiguity in the existing definition and identifies 13 types of schemes that
are not SPS, but for which uncertainty has existed in the past based on experience within the Regions. The report also
recommends that SPS should be classified based on the type of event to which the SPS responds and the consequence of
misoperation. Classification of SPS facilitates standard requirements commensurate with potential reliability risk. Four
classifications are proposed.
This report provides recommendations to address FERC concerns with PRC-012-0, PRC-013-0, and PRC-014-0, which assign
requirements to Regional Reliability Organizations. Recommendations are made to reassign requirements to specific users,
owners, and operators of the bulk power system to remedy this situation.
Project 2010-05.2 should consolidate the requirements pertaining to review, assessment, and documentation of SPS into
one standard that includes continent-wide procedures for reviewing new or modified SPS, for assessing existing SPS in
annual transmission planning assessments, and for periodic comprehensive SPS assessments. The project also should revise
requirements pertaining to analysis and reporting of SPS misoperations in a revision of standard PRC-016-0.1. Due to the
significant difference between protection systems and SPS, the subject of SPS misoperations should not be included in a
future revision of PRC-004. Given the scope of work and need for drafting team members with different subject matter
expertise it may be appropriate to sub-divide Project 2010-05.2 to address review, assessment and documentation of SPS
separately from analysis and reporting of misoperations. This report also provides recommendations for Standards
Committee consideration that are outside the scope of Project 2010-05.2. These additional recommendations pertain to
maintenance and testing and operational aspects of SPS.
2
The original scope of work involved the SPCS and the predecessor of SAMS, the Transmission Issues Subcommittee (TIS).
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Introduction
Problem Statement
The existing NERC Glossary of Terms definition for a Special Protection System (SPS or, as used in the Western
Interconnection, a Remedial Action Scheme or RAS) lacks clarity and specificity necessary for consistent identification and
classification of protection schemes as SPS or RAS across the eight NERC Regions, leading to inconsistent application of the
related NERC Reliability Standards. In addition, three of the related standards (PRC-012-0, PRC-013-0, and PRC-014-0) were
identified by FERC in Order No. 693 as fill-in-the-blank standards and consequently are not mandatory and enforceable.
NERC Standards Project 2010-05.2, Phase 2 of Protection Systems: SPS and RAS, will modify the current standards and
definitions related to SPS and RAS. The NERC Standards Committee has identified that prior to initiating a project to address
these issues, additional research is necessary to clearly define the problem and recommend solutions for consideration.
Background
NERC Definitions
The existing NERC Glossary of Terms defines an SPS and RAS as:
Special Protection System (Remedial Action Scheme)
An automatic protection system designed to detect abnormal or predetermined system conditions, and take corrective
actions other than and/or in addition to the isolation of faulted components to maintain system reliability. Such action
may include changes in demand, generation (MW and Mvar), or system configuration to maintain system stability,
acceptable voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load shedding or (b)
fault conditions that must be isolated or (c) out-of-step relaying (not designed as an integral part of an SPS). Also called
Remedial Action Scheme.
In this document, use of the term SPS in general discussions and proposals for future definitions and standards apply to
both SPS and RAS. Specific references to existing practices within Regions use the term SPS or RAS as appropriate for that
Region.
The NERC Glossary of Terms defines a Protection System as:
Protection System
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including batteries, battery chargers, and non-batterybased dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other
interrupting devices.
Inclusion of the words “protection system” in the term Special Protection System has raised questions whether this is an
intentional reference such that SPS are a subset of Protection Systems. Use of protection system (lower case) within the SPS
definition identifies that SPS are not Protection Systems. While SPS may include the same types of components as
Protection Systems, SPS are not limited to detecting faults or abnormal conditions and tripping affected equipment. SPS
may, for example, effect a change to the operating state of power system elements to preserve system stability or to avoid
unacceptable voltages or overloads in response to system events. There are many reasons for implementing an SPS; for
example, an SPS can be implemented to ensure compliance with the TPL Reliability Standards, to mitigate temporary
operating conditions or abnormal configurations (e.g., during construction or maintenance activities), or in instances where
system operators would not be able to respond quickly enough to avoid adverse system conditions.
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Introduction
A second area in which the existing SPS definition lacks clarity is the actions that are characteristics of SPS. The actions listed
in the definition are broad and may unintentionally include equipment whose purpose is not expressly related to preserving
system reliability in response to an event. Inclusion of any system taking “corrective action other than … isolation of faulted
components to maintain system reliability” could be deemed to include equipment such as voltage regulators and switching
controls for shunt reactive devices. This inclusion would then make these elements subject to single component failure
considerations (sometimes referred to as redundancy considerations), coordination, reporting, and maintenance and
testing requirements that may be required in the NERC Reliability Standards related to SPS.
This report proposes a revised definition of SPS to address these issues. Development of the proposed definition considered
other definitions, common applications, and existing practices regarding classification of SPS.
NERC Reliability Standards
The NERC Reliability Standards contain six standards in the protection and control (PRC) series that specifically pertain to
SPS.
•
PRC-012-0: Special Protection System Review Procedure
•
PRC-013-0: Special Protection System Database
•
PRC-014-0: Special Protection System Assessment
•
PRC-015-0: Special Protection System Data and Documentation
•
PRC-016-0.1: Special Protection System Misoperations
•
PRC-017-0: Special Protection System Maintenance and Testing
Three of these standards are not mandatory and enforceable because FERC identified them as fill-in-the-blank standards in
Order No. 693, Mandatory Reliability Standards for the Bulk-Power System. These standards assign the Regional Reliability
Organizations responsibility to establish regional procedures and databases, and to assess and document the operation,
coordination, and compliance of SPS. The deference to regional practices, coupled with lack of clarity in the definition of
SPS, preclude consistent application of requirements pertaining to SPS. This report provides recommendations that may be
implemented through the NERC Reliability Standards Development Process to consolidate the standards and provide
greater consistency and clarity regarding requirements.
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Chapter 1 – SPS Definition
Considerations for a Revised Definition
Other Definitions in Industry
3
Several IEEE papers define a similar term to SPS: System Integrity Protection System (SIPS). Adopting the SIPS definition is
not appropriate because it is more inclusive than NERC’s definition:
“The SIPS encompasses special protection system (SPS), remedial action schemes (RAS), as well as other system
4
integrity schemes, such as underfrequency (UF), undervoltage (UV), out-of-step (OOS), etc.”
NERC applies special consideration to UF and UV load shedding schemes in the Reliability Standards and considers OOS
relaying in the context of traditional protection systems. Thus, SIPS is not an appropriate term for use in the Reliability
Standards, and a new definition of SPS is more appropriate.
Common Application of SPS in Industry
Most SPS are used to address a range of system issues including stability, voltage, and loading concerns. Less common
applications include arresting sub-synchronous resonance and suppressing torsional oscillations. Actions taken by SPS may
include (but are not limited to): system reconfiguration, generation rejection or runback, load rejection or shedding,
reactive power or braking resistor insertion, and runback or fast ramping of HVdc.
SPS are often deployed because the operational solutions they facilitate are substantially quicker and less expensive to
implement than construction of transmission infrastructure. Permanent SPS have been implemented in some cases where
the cost associated with system expansion is prohibitive, construction is not possible due to physical constraints, or
obtaining permits is not feasible. In other cases temporary SPS have been implemented to maintain system reliability until
transmission infrastructure is constructed; or when a reliability risk is temporary (e.g., during equipment outages) and the
expense associated with permanent transmission upgrades is not justified.
The deployment of SPS adds complexity to power system operation and planning:
“Although SPS deployment usually represents a less costly alternative than building new infrastructure, it carries
with it unique operational elements among which are: (1) risks of failure on demand and of inadvertent activation;
(2) risk of interacting with other SPS in unintended ways; (3) increased management, maintenance, coordination
5
requirements, and analysis complexity.”
Subsequent sections of this report consider these three operational elements and provide recommendations regarding how
they should be addressed in the NERC Reliability Standards. A summary of the number of schemes identified as SPS or RAS
by Region is provided below.
Table 1: Overview of SPS by Region 6
Region
Total Number
Region
Total Number
FRCC
20
SERC
20
MRO
36
SPP
6
NPCC
117
TRE
24
RFC
47
WECC
192
3
One noteable reference, Madani, et al, “IEEE PSRC Report on Global Industry Experiences with System Integrity Protection
Schemes (SIPS),” IEEE Trans. on Power Delivery, Vol. 25, Oct. 2010.
4
Ibid.
5
McCalley, et al, “System Protection Schemes: Limitations, Risks, and Management”, PSERC Publication 10-19, Dec 2010.
6
Numbers for 2011 obtained from data reported in the NERC Reliability Metric ALR6-1.
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Chapter 1 – SPS Definition
Classification of SPS Types
Three regions classify SPS according to various criteria, including the type of event the SPS is designed to address as well as
the ability of the SPS to impact on a local versus wide-area reliability. The following information describes how NPCC, WECC
and TRE classify SPS. Please note that examples of regional practices are provided for illustration throughout this document,
but are not necessarily best practices or applicable to all Regions. Also in this context, what constitutes local versus widearea varies among Regions and is not based on the NERC glossary term Wide Area, which is specific to calculation of
7
Interconnection Reliability Operating Limits (IROL).
NPCC
Type I – A Special Protection System which recognizes or anticipates abnormal system conditions resulting from design
and operating criteria contingencies, and whose misoperation or failure to operate would have a significant adverse
impact outside of the local area. The corrective action taken by the Special Protection System along with the actions
taken by other protection systems are intended to return power system parameters to a stable and recoverable state.
Type II – A Special Protection System which recognizes or anticipates abnormal system conditions resulting from
extreme contingencies or other extreme causes, and whose misoperation or failure to operate would have a significant
adverse impact outside of the local area.
Type III – A Special Protection System whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for their classification:
Significant adverse impact – With due regard for the maximum operating capability of the affected systems, one or
more of the following conditions arising from faults or disturbances, shall be deemed as having significant adverse
impact:
a.
system instability;
b.
unacceptable system dynamic response or equipment tripping;
c.
voltage levels in violation of applicable emergency limits;
d.
loadings on transmission facilities in violation of applicable emergency limits;
e.
unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and number of system
elements contained will vary based on system characteristics. A local area may be relatively large geographically with
relatively few buses in a sparse system, or be relatively small geographically with a relatively large number of buses in a
densely networked system.
W ECC
Local Area Protection Scheme (LAPS): A Remedial Action Scheme (RAS) whose failure to operate would NOT result in
any of the following:
•
Violations of TPL-(001 thru 004)-WECC-1-CR – System Performance Criteria,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
7
The NERC Glossary defines Wide Area as “The entire Reliability Coordinator Area as well as the critical flow and status
information from adjacent Reliability Coordinator Areas as determined by detailed system studies to allow the calculation
of Interconnected Reliability Operating Limits.”
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Chapter 1 – SPS Definition
Wide Area Protection Scheme (WAPS): A Remedial Action Scheme (RAS) whose failure to operate WOULD result in any
of the following:
•
Violations of TPL-(001 thru 004)-WECC-1-CR – System Performance Criteria,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
Safety Net: A type of Remedial Action Scheme designed to remediate TPL-004-0 (System Performance Following
Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D)), or other extreme
events.
TR E:
(a) A “Type 1 SPS” is any SPS that has wide-area impact and specifically includes any SPS that:
(i) Is designed to alter generation output or otherwise constrain generation or imports over DC Ties; or
(ii) Is designed to open 345 kV transmission lines or other lines that interconnect Transmission Service Providers
(TSPs) and impact transfer limits.
(b) A “Type 2 SPS” is any SPS that has only local-area impact and involves only the facilities of the owner-TSP.
These three regional classifications can be roughly mapped:
•
NPCC Type I = WECC WAPS = TRE Type 1
•
NPCC Type III = WECC LAPS = TRE Type 2
•
NPCC Type II = WECC Safety Net
SPS classification differentiates the reliability risk associated with SPS and provides a means to establish more or less
stringent requirements consistent with the reliability risk. For example, it may be appropriate to establish less stringent
requirements pertaining to monitoring or single component failure of SPS that present a lower reliability risk. A
recommendation for classification of SPS is included with the proposed definition and subsequent discussion of standard
requirements includes recommendations where different requirements based on classification are deemed appropriate.
Common Exclusions from the SPS Definition in Industry
Exclusions provide a means to assure that specific protection or control systems are not unintentionally included as SPS.
The NERC glossary definition of SPS states that “An SPS does not include (a) underfrequency or undervoltage load shedding
or (b) fault conditions that must be isolated or (c) out-of-step relaying (not designed as an integral part of an SPS).”
Even with the exclusions in the NERC definition, other commonly applied protection and control systems meet the general
language in the SPS definition. Considerable effort has been expended by industry discussing what systems are SPS. NPCC
and SERC have documented examples of exclusions to the SPS definition in their regional guidelines. NPCC explicitly
excludes “Automatic underfrequency load shedding; Automatic undervoltage load shedding and manual or automatic
8
locally controlled shunt devices.” SERC’s SPS guideline calls out specific exclusions as follows:
8
a.
UFLS and/or UVLS,
b.
Fault conditions that must be isolated including bus breakup / backup / breaker failure
protection,
c.
Relays that protect for specific equipment damage (such as overload, overcurrent, hotspot,
reclose blocking, etc.),
d.
Out of step relaying,
e.
Capacitor bank / reactor controls,
NPCC Glossary of Terms Used by Directories
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Chapter 1 – SPS Definition
f.
Load Tap Changer (LTC) controls,
g.
Automated actions that could be performed by an operator in a reasonable amount of time,
including alternate source schemes, and
h.
Scheme that trips generation to prevent islanding
A recommended list of protection and control systems that should be excluded from classification as SPS is included with
the proposed definition.
Exclusion for Operator Aides
SAMS and SPCS considered a number of factors in discussing this subject including:
1) whether the actions are required to be completed with such urgency that it would be difficult for an operator to
react and execute in the necessary time, and
2) whether the required actions are of such complexity or across such a large area that it would be difficult for an
operator to perform the actions in the necessary time.
It is difficult to address these questions with concise and measurable terms, making it difficult to explicitly exclude them in
the definition without introducing ambiguous terms counter to the objective of providing needed clarity in the SPS
definition. Whether its existence is based upon convenience or not, any automated system with the potential to impact
bulk power system reliability should be defined and expressed to the appropriate authority (e.g., Planning Coordinator,
Reliability Coordinator) for the purposes of system modeling and coordination studies, to ensure that these systems are
properly coordinated with other protection and control systems, and to ensure that inadvertent operations do not result in
adverse system impacts.
On these bases, SAMS and SPCS decided not to provide an exclusion for schemes based on a general criterion as to whether
the scheme automates actions that an operator could perform in a reasonable amount of time or schemes installed for
operator convenience. However, SAMS and SPCS do recommend exclusions for specific applications that meet these criteria
such as automatic sequences that are initiated manually by an operator. Furthermore, any scheme that is not installed “to
meet system performance requirements identified in the NERC Reliability Standards, or to limit the impact of two or more
elements removed, an extreme event, or Cascading” would be excluded by definition, regardless of whether it is installed to
assist an operator.
Voltage Threshold
All elements, at any voltage level, of an SPS intended to remediate performance issues on the bulk electric system (BES), or
of an SPS that acts upon BES elements, should be subject to the NERC requirements.
Proposed Definition
The proposed definition clarifies the areas that have been interpreted differently between individual entities and within
Regions, in some cases leading to differing regional definitions of SPS. The proposed definition provides a framework for
differentiating among SPS with differing levels of reliability risk and will support the drafting of new or revised SPS
standards.
Special Protection System (SPS)
A scheme designed to detect predetermined system conditions and automatically take corrective actions,
other than the isolation of faulted elements, to meet system performance requirements identified in the
NERC Reliability Standards, or to limit the impact of: two or more elements removed, an extreme event,
or Cascading.
Subject to the exclusions below, such schemes are designed to maintain system stability, acceptable
system voltages, acceptable power flows, or to address other reliability concerns. They may execute
actions that include but are not limited to: changes in MW and Mvar output, tripping of generators and
other sources, load curtailment or tripping, or system reconfiguration.
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Chapter 1 – SPS Definition
The following schemes do not constitute an SPS in and of themselves:
a)
Underfrequency or undervoltage load shedding
b) Locally sensing devices applied on an element to protect it against equipment damage for nonfault conditions by tripping or modifying the operation of that element, such as, but not limited
to, generator loss-of-field or transformer top-oil temperature
c)
Autoreclosing schemes
d) Locally sensed and locally operated series and shunt reactive devices, FACTS devices, phaseshifting transformers, variable frequency transformers, generation excitation systems, and tapchanging transformers
e)
Schemes that prevent high line voltage by automatically switching the affected line
f)
Schemes that automatically de-energize a line for non-fault operation when one end of the line is
open
g)
Out-of-step relaying
h) Schemes that provide anti-islanding protection (e.g., protect load from effects of being isolated
with generation that may not be capable of maintaining acceptable frequency and voltage)
i)
Protection schemes that operate local breakers other than those on the faulted circuit to
facilitate fault clearing, such as, but not limited to, opening a circuit breaker to remove infeed so
protection at a remote terminal can detect a fault or to reduce fault duty
j)
Automatic sequences that proceed when manually initiated solely by an operator
k)
Sub-synchronous resonance (SSR) protection schemes
l)
Modulation of HVdc or SVC via supplementary controls such as angle damping or frequency
damping applied to damp local or inter-area oscillations
m) A Protection System that includes multiple elements within its zone of protection, or that isolates
more than the faulted element because an interrupting device is not provided between the
faulted element and one or more other elements
SPS are categorized into four distinct types. These types may be subject to different requirements within
the NERC Reliability Standards.
•
Type PS (planning-significant): A scheme designed to meet system performance requirements
identified in the NERC Reliability Standards, where failure or inadvertent operation of the
scheme can have a significant impact on the BES.
•
Type PL (planning-limited): A scheme designed to meet system performance requirements
identified in the NERC Reliability Standards, where failure or inadvertent operation of the
scheme can have only a limited impact on the BES.
•
Type ES (extreme-significant): A scheme designed to limit the impact of two or more elements
removed, an extreme event, or Cascading, where failure or inadvertent operation of the scheme
can have a significant impact on the BES.
•
Type EL (extreme-limited): A scheme designed to limit the impact of two or more elements
removed, an extreme event, or Cascading, where failure or inadvertent operation of the scheme
can have only a limited impact on the BES.
An SPS is classified as having a significant impact on the BES if failure or inadvertent operation of the
scheme results in any of the following:
•
Non-Consequential Load Loss ≥ 300 MW
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Chapter 1 – SPS Definition
•
Aggregate resource loss (tripping or runback of generation or HVdc) > the largest Real Power
9
resource within the interconnection
•
Loss of synchronism between two or more portions of the system each including more than one
generating plant
•
Negatively damped oscillations
If none of these criteria are met, the SPS is classified as having a limited impact on the BES.
Definition of Significant and Limited Impact
The parameters used to define the bright line between “significant” and “limited” impacts are proposed to consider only
the electrical scale of the event. Defining the bright line in this way eliminates the difficulty in distinguishing the geographic
impact of an SPS as either “wide” or “local.”
NERC Standard EOP-004-1, DOE Form OE-417 Electric Emergency Incident and Disturbance Report, establishes the criteria
by which an event is categorized as a Disturbance and requires a disturbance report. In terms of SPS, the proposed criteria
for significant impact mirrors EOP-004-1 by including a non-consequential load loss value of 300 MW.
NERC Reliability Standards require consideration of loss of any generating unit; therefore, generating unit loss would not
impact reliability of the bulk power system unless the combined capacity loss exceeds the largest unit within the
interconnection. The generation loss level was selected as a loss greater than the largest unit within an interconnection on
this basis.
Tripping multiple generating units exceeding the capacity of the largest unit within an interconnection, system separation
(loss of synchronism) that results in isolation of a portion of an interconnection, or system oscillations that increase in
magnitude (negatively-damped) are indicators of adverse impact to the reliability of an interconnection. These criteria
identify system performance indicative of the potential for instability, uncontrolled separation, or cascading outages,
without requiring detailed analyses to confirm the extent to which instability, uncontrolled separation, or cascading outages
may occur. These indicators, combined with the loss of load criterion, are proposed to identify the potential reliability risk
associated with failure of a SPS. Subsequent sections of this report recommend requirements for assessment and design of
SPS based on whether the potential reliability risk associated with the SPS are significant versus limited impacts.
The proposed thresholds differentiate between significant and limited impact. While it should be clear there is no upper
threshold on what constitutes a significant impact, there also is no lower threshold proposed as to what constitutes limited
impact. Whether a scheme is an SPS is determined by the definition; significant and limited impact are used only to classify
SPS. For example, if a scheme is installed to meet system performance requirements identified in the NERC Reliability
Standards then it is an SPS regardless of its potential impact. A failure of the SPS would result in a violation of a NERC
Reliability Standard. Thus, excluding a scheme with impact below a certain threshold would undermine the reliability
objective of the standard requirement the scheme is installed to address.
9
I.e., Eastern, Western, ERCOT, or Quebec Interconnection.
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Chapter 2 – Design and Maintenance Requirements
Under the proposed definition, SPS are implemented to preserve acceptable system performance, and as such may be
critical to power system reliability and therefore subject to single component failure considerations, and maintenance and
testing requirements outlined in the PRC standards.
General Design Considerations
Aside from the single component failure, and maintenance and testing considerations outlined below, Disturbance
Monitoring Equipment should be provided in the design of an SPS to permit analysis of the SPS performance following an
event. Also, as with other automated systems, the design of an SPS should facilitate its maintenance and testing.
SPS Single Component Failure Requirements
Requirement R1.3 in PRC-012-0 requires SPS owners to demonstrate an SPS is designed so that a single SPS component
failure, when the SPS was intended to operate, does not prevent the interconnected transmission system from meeting the
performance requirements defined in NERC Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0. This requirement
should be retained in future standards such that Types PS and PL SPS are required to be designed so that power system
performance meets the performance requirements of TPL-001-0, TPL-002-0, or TPL-003-0, in the event of a single
component failure. The design of Type PS and PL SPS can provide the required performance through any of the methods
outlined below, or a combination of these methods:
1.
Arming more load or generation than necessary to meet the intended results. Thus the failure of the scheme to
drop a portion of load or generation would not be an issue. In this context it is necessary to arm the tripping of
more load delivery points or generating units rather than simply arming more MW of load or generation. When
this option is used, studies of the SPS design must demonstrate that tripping the total armed amount of load or
generation will not cause other adverse impacts to reliability.
2.
Providing redundancy of SPS components listed below.
•
Any single ac current source and/or related input to the SPS. Separate secondary windings of a free-standing
current transformer (CT) or multiple CTs on a common bushing should be considered an acceptable level of
redundancy.
•
Any single ac voltage source and/or related input to the SPS. Separate secondary windings of a common
capacitance coupled voltage transformer (CCVT), voltage transformer (VT), or similar device should be
considered an acceptable level of redundancy.
•
Any single device used to measure electrical quantities used by the SPS.
•
Any single communication channel and/or any single piece of related communication equipment used by the
SPS.
•
Any single computer or programmable logic device used to analyze information and provide SPS operational
output.
•
Any single element of the dc control circuitry that is used for the SPS, including breaker closing circuits.
•
Any single auxiliary relay or auxiliary device used by the SPS.
•
Any single breaker trip coil for any breaker operated by the SPS.
•
Any single station battery or single charger, or other single dc source, where central monitoring is not
provided for both low voltage and battery open conditions.
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Chapter 2 – Design and Maintenance Requirements
10
3.
Using remote or time delayed actions such as breaker failure protection or alternative automatic actions to back
up failures of single components (e.g., an independent scheme that trips an element if an overload exists for
longer than the time necessary for the SPS to take action). The backup operation would still need to provide
mitigation to meet the necessary result in the required timeframe.
4.
For Type PL SPS, manual backup operation may be used to address the failure of a single SPS component if studies
are provided to show that implemented procedures will be effective in providing the required response when a
SPS failure occurs. The implemented procedures will include alarm response and manual operation time
requirements to provide the backup functions.
Some SPS utilize an Energy Management System (EMS) system for transmitting signals or calculating information necessary
for SPS operation such as the amount of load or generation to trip. Loss of the EMS system must be considered when
assessing the impact of a single component failure. For example, when the EMS is used to transmit a signal, a separate
communication path must be available. When a non-redundant EMS provides a calculated value to two otherwise
independent systems, a backup calculation or default value must be provided to the SPS in the event of an EMS failure.
Types ES and EL SPS are designed to provide system protection against extreme events. The events that Types ES and EL SPS
are intended to address have a lower probability of occurrence and the TPL standards do not require mitigation for these
events. Dependability of SPS operation is therefore not critical for these events and, consistent with the existing standards,
these SPS should not be required to perform their protection functions even with a single component failure. Design
requirements for Type ES SPS should emphasize security; however, in some cases Type ES SPS are installed to address an
event with consequences so significant (e.g., system separation or collapse of an interconnection) that consideration should
be given to both dependability and security. In consideration that the addition of redundancy in some cases might make the
11
SPS less secure, such cases may warrant implementation of a voting scheme .
Maintenance and Testing
The Project 2007-17, Protection System Maintenance and Testing, drafting team revised PRC-005 to include maintenance
12
and testing requirements for SPS contained in PRC-017-0. All of the existing requirements in PRC-017-0 that are based on
a reliability objective are mapped to PRC-005-2. However, this report identifies two subjects that are not covered in either
the existing standard or the proposed standard:
•
Complex SPS require different procedures than those used for maintenance of protection systems.
•
Maintenance of non-protection system components used in SPS is not addressed in any existing NERC Reliability
Standards.
These subjects should be addressed in a future revision of PRC-005 or development of a separate standard.
10
In this context it is not intended that breaker failure protection must be redundant; rather, that breaker failure protection
may be relied on to meet the design requirements (e.g., if an SPS required tripping a breaker with a single trip coil).
11
A voting scheme achieves both dependable and secure operation by requiring, for example, two out of three schemes to
detect the condition prior to initiating action.
12
PRC-005-2 was adopted by the NERC Board of Trustees on November 7, 2012
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Chapter 3 – Study and Documentation Requirements
Review and Approval of New or Modified SPS
Requirement R1 in PRC-012-0 requires each Regional Reliability Organization to have a documented review procedure to
ensure that SPS comply with regional criteria and NERC Reliability Standards. However, the potential for SPS interaction and
for SPS operation or misoperation to have inter-regional impacts suggests that a uniform procedure for reviewing SPS is
important to ensure bulk power system reliability. This report recommends fundamental aspects that should be included in
a continent-wide SPS review procedure and included in the revised reliability standards pertaining to SPS. The review
process should be conducted by an entity or entities with the widest possible view of system reliability, and must be a user,
owner, or operator of the bulk power system. To assure that both planning and operating views are evaluated before a new
or modified SPS is placed in service, responsibility for reviewing and approving implementation of SPS should be assigned to
the Reliability Coordinator and Planning Coordinator. Ideally these reviews should be performed on a regional or
interconnection-wide basis. If in the future an entity is registered as the Reliability Assurer for each Region, the
responsibility for performing these reviews, or alternately for coordinating these reviews, should be assigned to the
Reliability Assurer.
A continent-wide review process should be established in a revised reliability standard that includes the following aspects:
13
•
The SPS owner should be required to obtain approval from its Reliability Coordinator and its Planning
14
Coordinator in whose area the SPS is installed prior to placing a new or modified SPS in service.
•
An entity proposing a new or modified SPS should be required to file an application with its Reliability Coordinator
and Planning Coordinator that includes the following information:
o
A document outlining the details of the SPS as specified below in the section titled, Data Submittals by Entities
that Own SPS.
o
Studies that demonstrate the operation, coordination, and effectiveness of the SPS, including the impacts of
correct operation, a failure to operate, and inadvertent operation. The study report should include the
15
following:
Entity conducting the SPS study
Study completion date
Study years
System conditions
Contingencies analyzed
Demonstration that the SPS meets criteria discussed in the Design Considerations chapter of this report
Discussion of coordination of the SPS with other SPS, UFLS, UVLS, and protection systems
•
The Reliability Coordinator and Planning Coordinator should be required to provide copies of the application and
supporting information to Transmission Planners, Transmission Operators, and Balancing Authorities within their
area, and to adjacent Reliability Coordinators and Planning Coordinators.
•
Entities receiving the application should be allowed to provide comments to the Reliability Coordinator and
Planning Coordinator.
13
In cases where more than one entity owns an SPS, the standards should designate that a designated “reporting entity” be
responsible for transmitting data to the Reliability Coordinator and Planning Coordinator, while all owners retain
responsibility for other requirements such as maintenance and testing.
14
In cases where an SPS has components installed in or takes action in more than one Reliability Coordinator area or
Planning Coordinator area, all affected Reliability Coordinators and Planning Coordinators should have approval authority.
15
The same documentation requirements should apply to Periodic Comprehensive Assessments of SPS Coordination.
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Chapter 3 – Study and Documentation Requirements
•
When deciding whether to approve an SPS, the Reliability Coordinator and the Planning Coordinator in whose area
the SPS is to be installed or modified should be required to consider supporting information provided with the
application; comments from Transmission Planners, Transmission Operators, and Balancing Authorities and other
Reliability Coordinators and Planning Coordinators; and any supplemental information provided by the SPS owner.
•
The basis of the Reliability Coordinator and Planning Coordinator approval should be limited to whether all
required information has been submitted and the studies are sufficient to support that all performance
requirements are met.
Assessment of Existing SPS
Study of SPS in Annual Transmission Planning Assessments
Requirement R1 in PRC-014-0 specifically addresses assessment of the operation, coordination, and effectiveness of all SPS
and assigns this responsibility to the Regional Reliability Organization. Reliability standards must assign responsibility to
owners, operators, and users of the bulk power system. For assessments of SPS, it is important to identify an entity with the
necessary expertise in system studies and a wide-area view to facilitate coordination of SPS across the system. Instead of
assigning this responsibility to the Regional Reliability Organization or the Regional Entity, the assessment responsibility
should be assigned to the Planning Coordinator and Transmission Planner for SPS within their specific area.
Annually, the Planning Coordinator and Transmission Planner should review the operation, coordination, and effectiveness
of the SPS, including the impacts of correct operation, a failure to operate, and inadvertent operation. If system changes
have occurred which can affect the operation of the SPS, annual studies should include system conditions and
contingencies modeled in the study supporting the application for installation of or modifications to an SPS.
Any issues identified should be documented and submitted to the Reliability Coordinator and the SPS owner. The Reliability
Coordinator and Planning Coordinator should be required to determine, in consultation with the SPS owner, whether a
corrective action plan is required, and if so, whether the SPS can remain in-service or must be removed from service until a
corrective action plan is implemented. If a corrective action plan is required, the SPS owner should be required to submit an
application for a modified SPS as described above in the section titled Review and Approval of New or Modified SPS.
Periodic Comprehensive Assessments of SPS Coordination
Comprehensive assessment should occur every five years, or sooner, if significant changes are made to system topology or
operating characteristics that may impact the coordination among SPS and between SPS and UFLS, UVLS, and other
protection systems. Responsibility for the comprehensive assessment should be assigned to the Reliability Coordinator to
achieve the wide-area review necessary for a comprehensive assessment. Planning Coordinators, Transmission Planners,
Transmission Operators, Balancing Authorities, and adjacent Reliability Coordinators should be required to provide support
to the Reliability Coordinator when requested to do so. As part of the periodic review the Reliability Coordinator should be
required to request the Planning Coordinator and Transmission Planner to assess and document whether the SPS is still
necessary, serves its intended purpose, meets criteria discussed in the Design Considerations chapter of this report,
coordinates with other SPS, UFLS, UVLS, and protection systems, and does not have unintended adverse consequences on
reliability.
The Reliability Coordinator should be required to provide its periodic assessment to Planning Coordinators, Transmission
Planners, Transmission Operators, and Balancing Authorities in its area, and to adjacent Reliability Coordinators, and should
be required to consider comments provided by these entities. Any issues identified with an SPS should be documented and
submitted to the SPS owner. If any concerns are identified, the Reliability Coordinator and the Planning Coordinator in
whose area the SPS is installed should determine, in consultation with the SPS owner, whether a corrective action plan is
required, and if so, whether the SPS can remain in-service or must be removed from service until a corrective action plan is
implemented. If a corrective action plan is required, the SPS owner should be required to submit an application for a
modified SPS as described above in the section titled Review and Approval of New or Modified SPS.
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Chapter 3 – Study and Documentation Requirements
Documentation Requirements
Data Submittals by Entities that Own SPS
Reliability standard PRC-015-0 establishes requirements for SPS owners to provide data for existing and proposed SPS as
specified in reliability standard PRC-013-0 Requirement R1. PRC-013-0 establishes the data provided shall include the
following:
•
Design Objectives — Contingencies and system conditions for which the SPS was designed
•
Operation — The actions taken by the SPS in response to Disturbance conditions
•
Modeling — Information on detection logic or relay settings that control operation of the SPS
This requirement should be carried forward to the revised standards for the SPS owner to provide detailed information
regarding the conditions of SPS operation. However, this requirement should be modified to ensure that communication of
this information is clear and understandable to all entities that require the information to plan and operate the bulk power
system (e.g., Planning Coordinators, Transmission Planners, Reliability Coordinators, Transmission Operators, and Balancing
Authorities). Additional specificity should be added to this list of data to assure that sufficient information is provided for
entities to understand and model SPS operation.
Since SPS design and complexity vary considerably, a brief description of the action taken when certain system conditions
are detected generally does not provide a sufficient level of detail. Conversely, logic and control wiring diagrams may
provide too much detail that is not readily understood except by the SPS owner’s protection and control engineers. To
achieve an appropriate level of detail that provides a common understanding by the SPS owner and other entities, the SPS
owner should work with the Transmission Planner to develop a document outlining the details of the SPS operation
specifically tailored to the needs and knowledge level of the entities that require this information to plan and operate the
bulk power system. The document should include the following:
•
SPS name
•
SPS owner
•
Expected in-service date
•
Whether the SPS is intended to be permanent or temporary
•
SPS classification (per revised definition), and documentation or explanation of how the SPS mitigates the planning
or extreme event and why the impact is significant or limited
•
Logic diagram, flow chart, or truth table documenting the scheme logic and illustrating how functional operation is
accomplished
•
Whether the SPS logic is:
•
16
o
Event-based
o
Parameter-based
o
A combination of event-based and parameter-based
17
System performance criteria violation necessitating the SPS (e.g., thermal overload, angular instability, poor
oscillation damping, voltage instability, under-/over-voltage, slow voltage recovery)
16
Event-based schemes directly detect outages and/or fault events and initiate actions such as generator/load tripping to
fully or partially mitigate the event impact. This open-loop type of control is commonly used for preventing system
instabilities when necessary remedial actions need to be applied as quickly as possible.
17
Parameter-based schemes measure variables for which a significant change confirms the occurrence of a critical event.
This is also a form of open-loop control but with indirect event detection. The indirect method is mainly used to detect
remote switching of breakers (e.g., at the opposite end of a line) and significant sudden changes which can cause
instabilities, but may not be readily detected directly. To provide timely remedial action execution, the measured variables
may include power, angles, etc., and/or their derivatives.
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Chapter 3 – Study and Documentation Requirements
•
Parameters and equipment status monitored as inputs to the SPS (e.g., voltage, current or power flow, breaker
position) and specific monitoring points and locations
•
Under what conditions the SPS is armed (e.g., always armed, armed for certain system conditions, actuation
thresholds)
•
Whether arming is accomplished automatically or manually, if required
•
Arming criteria – analog quantities and/or equipment status monitored to determine existence of the system
condition for which SPS is armed (e.g., generation/load patterns, reactive power reserves, facility loading)
•
Action taken – for example: transmission facilities switched in or out; generators tripped, runback, or started; load
dropped; tap setting changed (phase-shifting transformer); controller set-point changed (AVR, SVC, HVdc
converter); turbine fast valving or generator excitation forcing; braking resistor insertion
•
Time to operate, including intentional time delays (e.g., timer settings) and inherent delays (e.g., relay operating
time)
•
Information with sufficient detail necessary to model the SPS.
SPS Database
PRC-013-0, Requirement R1 requires the Regional Reliability Organization to maintain an SPS database, including data on
design objectives, operation, and modeling of each SPS. Similar to the other requirements presently assigned to the
Regional Reliability Organization, this requirement should be assigned to a user, owner, or operator of the bulk power
system. To minimize the number of databases and facilitate sharing of information with entities that require SPS data to
plan and operate the bulk power system, this requirement should be assigned to the Planning Coordinator. The Planning
18
Coordinator should be required to provide its database to NERC for the purpose maintaining a continent-wide data base
that NERC would make available to Reliability Coordinators, Transmission Operators, Balancing Authorities, Planning
Coordinators, and Transmission Planners that require this data. The database should contain information for each SPS as
described above in the section titled, Data Submittals by Entities that Own SPS.
18
The requirement in a NERC Reliability Standard would be applicable to the Planning Coordinator; the responsibility for
NERC to maintain a continent-wide database should be addressed outside the standard.
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Chapter 4 – Operational Requirements
Due to their unique nature, SPS may have special operational considerations, with potentially differing requirements among
the proposed types for monitoring, notification of status, and the response time required to address SPS failure.
Furthermore, consideration should be given to the documentation of procedures for operator interaction with SPS, and
how operators should respond to SPS failures.
One entity should be assigned primary responsibility for monitoring, coordination, and control of an SPS. Depending on the
complexity, this responsible party may be a Reliability Coordinator, Balancing Authority, or Transmission Operator. Complex
SPS may have multiple owners or affected entities, including different functional entities and the chain of notification and
control should be clearly established.
Monitoring of Status
Existing NERC Reliability Standard IRO-005-3.1a, Requirement R1.1 requires Reliability Coordinators to monitor SPS.
Similarly PRC-001-1, Requirement R6 requires Balancing Authorities and Transmission Operators to monitor SPS. The SPS
standards should establish the level of monitoring capability that must be provided by the SPS owner. Classification of the
SPS will dictate its design criteria and may lend itself to different levels of monitoring.
All SPS should be monitored by SCADA/EMS with real-time status communicated to EMS that minimally includes whether
the scheme is in-service or out-of-service, and the current operational state of the scheme. For SPS that are armed
manually the arming status may be the same as whether the SPS is in-service or out-of-service. For SPS that are armed
automatically these two states are independent because an SPS that has been placed in-service may be armed or unarmed
based on whether the automatic arming criteria have been met. In cases where the classification of the SPS requires
redundancy, the minimal status indications should be provided for each system. The minimum status is sufficient for
operational purposes; however, where possible it may be useful to provide additional information regarding partial failures
or the status of critical components to allow the SPS owner to more efficiently troubleshoot a reported failure. Whether
this capability exists will depend in part on the design and vintage of equipment used in the SPS. While all schemes should
be required to provide the minimum level of monitoring, new schemes should be designed with the objective of providing
monitoring similar to what is provided for microprocessor-based protection systems.
Similarly, the SCADA/EMS presentation to the operator would need to indicate the criticality of the scheme (e.g., through
the use of audible alarms and a high priority in the alarm queue). The operator would be expected to know how to respond
depending on the nature of the issue detected, as some partial SPS failures might not result in a complete failure of the
scheme.
In cases where SPS cross ownership and operational boundaries, it is important that all entities involved with the SPS are
provided with an appropriate level of monitoring.
Notification of Status
Since the owner and operator of an SPS or component are often different organizations, and because SPS may cross entity
boundaries, it is important that the SPS status is communicated appropriately between entities. Existing NERC Reliability
Standards already require some level of notification of SPS status by Reliability Coordinators, Balancing Authorities and
19
Transmission Operators. Furthermore, SPS owners (e.g., Transmission Owner, Generator Owner) should be responsible
for communicating scheme or component issues to the operating organizations (e.g., Transmission Operator, Generator
Operator), who should then be responsible for communicating the issues to the involved Reliability Coordinator, Balancing
Authority, and other Transmission Operators or Generator Operators that might rely on the SPS (for example, in setting
operating limits).
The required timing associated with such notification will depend on the type of scheme; for example, the misoperation of
a Type PS or ES scheme would require rapid notification to all interested parties. In general, the more critical a scheme is to
the reliability of the system, the then more important its notification and response; however, it is also important that some
19
See, for example, IRO-005-3.1a Requirement R9 and PRC-001-1, Requirement R6.
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Chapter 4 – Operational Requirements
level notification be made for all schemes, due to the complex nature of SPS and their interaction with each other, to allow
entities to understand the reliability impact of a neighboring entity’s SPS failure or misoperation.
Response to Failures
As with many of the other issues, the response time required to address SPS failure is tightly coupled to the potential
impact of the SPS as well as the operating conditions at the time of failure. For example, if the SPS is intended to address an
event with a significant impact such as an IROL, then any corrective action in response to a misoperation would need to be
20
taken in 30 minutes or less, consistent with the TV associated with the IROL. On the other hand, depending on the
operating conditions, a particular scheme’s unavailability may not result in an adverse impact to reliability. Actions taken
following an SPS failure should consider whether the failure affects dependability or security of the SPS and the potential
impact to reliability.
Generally speaking, the SPS failure modes are known and the necessary corrective actions are documented (e.g.,
contingency plans) so that the system can be placed in a safe operating state. In any case, a full or partial failure of an SPS
requires that the system performance level provided by having the SPS in service is met, or a more conservative and safe
operating condition would need to be achieved, in a timeframe appropriate for the nature of the SPS and operating
conditions. When one system of a redundant SPS fails, the action taken by the operator may depend on the system
conditions the SPS is installed to address and the operating conditions at the time of the failure. For example, an operator
may respond to failure of one system by operating to higher equipment ratings when an SPS is installed to address thermal
loading violations. However, the operator may not be able to rely on the remaining system of a redundant SPS when the
SPS is installed to prevent instability, system separation, or cascading outages, in which case the operator must reduce
transfers or take other actions to secure the system.
Operational Documentation
Operational documentation is necessary to provide the operator with enough information to understand all aspects of the
scheme and is used to provide knowledge transfer as staff changes occur. Overall documentation requirements are
identified in the section on Study and Documentation Requirements; however, the operator does not require all
information provided by the SPS owner for the database maintained by the Planning Coordinator. The operational
documentation is sometimes called a “description of operations” and provides the operation actions for the following
areas:
•
General Description – This provides an overview of the purpose of the scheme including the monitoring, set points
and actions of the scheme. The operator and other stake holders can use this information to understand the need
for the scheme.
•
Operation – This will provide the specific information concerning, arming, alarming, and actions taken by this
scheme including the monitoring points of the scheme. The operator can use this information to provide triage and
plan a course of action concerning restoration of the electric system. This information should provide an
understanding of what has operated, why these elements have been impacted, and possible mitigations or
restoration activities.
•
Failures, Alarms, Targeting – This information will provide the operator and first responders with descriptions of
alarms and targets and the actions needed when the scheme is rendered unusable either during maintenance or
because of a failure. The instructions will guide the operator on how to respond to component failures that
partially impair the scheme or those failures that might disable entire scheme.
Regulatory agencies provide oversight of these schemes and require owners of these schemes to provide descriptions and
operational information. NERC PRC-015 requires owners to provide description of schemes and the Study and
Documentation Requirements section of this report proposes specific documentation requirements for inclusion in a
revised standard. In addition to NERC, some Regional Entities also require SPS owners to provide the Region with additional
information concerning the operations of the schemes. Some regional regulatory agencies also require the owners to verify
that they have taken certain actions after a misoperation or a failure of these schemes.
20
Specifically, TV is discussed in NERC Reliability Standard IRO-009-1, Requirement R2.
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Chapter 5 – Analysis of SPS Operations
Operations of SPS provide an opportunity to assess their performance in actual operating power systems, as opposed to
assessing the impact through a preconceived set of system studies. Analysis of SPS operations is presently addressed in
PRC-012-0 and PRC-016-0.1, which establish requirements for Regional Reliability Organizations and SPS owners
respectively. PRC-012-0 requires that each Regional Reliability Organization establish a regional definition of an SPS
misoperation (R1.6), as well as requirements for analysis and documentation of corrective action plans for all SPS
misoperations (R1.7). PRC-016-0.1 requires that SPS owners analyze their SPS operations and maintain a record of all
misoperations in accordance with their regional SPS review procedure (R1) and that SPS owners take corrective actions to
avoid future misoperations (R2).
PRC-012-0 is one of the standards identified in FERC Order No. 693 as a fill-in-the-blank standard and this standard
therefore is not mandatory and enforceable. SAMS and SPCS have not identified any rationale for having regional
definitions of an SPS misoperation or regional processes for analyzing SPS operations. Establishment of a continent-wide
definition and review process will facilitate meaningful metrics for assessing the impact of SPS misoperations on bulk power
system reliability. Rather than revising PRC-012-0 to assign responsibility for developing regional definitions and review
processes to a user, owner, or operator of the bulk power system, this report recommends that one continent-wide
definition and review process should be established through the NERC Reliability Standard Development Process, and that
criteria be established for SPS owners to follow a continent-wide review process in place of the existing requirements in
PRC-016-0.1.
SPS Misoperation Definition
Establishing a definition of an SPS misoperation must account for the many different aspects affecting whether operation of
an SPS achieves its desired effect on power system performance. In addition to aspects traditionally considered in assessing
protection system misoperations such as failure to operate and unnecessary operation, analysis of an SPS operation also
must consider whether the action was properly initiated and whether the initiated action achieved the desired power
system performance. This report proposes that a tiered definition be used to assess which aspects of an SPS operation are
reportable for metric purposes, which require analysis and reporting to the Reliability Coordinator and Planning
Coordinator, and which require a corrective action plan. The following definition is recommended for an SPS misoperation.
SPS Misoperation
A SPS Misoperation includes any operation that exhibits one or more of the following attributes:
a.
Failure to Operate – Any failure of a SPS to perform its intended function within the designed time when
system conditions intended to trigger the SPS occur.
b.
Unnecessary Operation – Any operation of a SPS that occurs without the occurrence of the intended system
trigger condition(s).
c.
Unintended System Response – Any unintended adverse system response to the SPS operation.
d.
Failure to Mitigate – Any failure of the SPS to mitigate the power system conditions for which it is intended.
The SPS review process should include requirements based on the SPS misoperation definition as follows:
•
The SPS owner must provide analysis of all misoperations to its Reliability Coordinator and Planning Coordinator.
•
The SPS owner must develop and implement a corrective action plan for all SPS misoperations.
•
Reporting for reliability metric purposes should be limited to SPS misoperations that exhibit attributes (a) or (b) of
the proposed definition, but should be addressed outside PRC-016-1, in a manner similar to the process under
development for reporting protection system misoperations in Project 2010-05.1 Protection Systems: Phase 1
(Misoperations).
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Chapter 5 – Analysis of SPS Operations
SPS Operation Review Process
The review process should be included in a revised version of PRC-016 and PRC-012-0 should be retired upon approval of a
continent-wide definition and revised PRC-016. The SPS operation review process should require that SPS owners analyze
all SPS operations in sufficient detail to determine whether or not the response of the power system to the SPS operation is
appropriate to meeting the purpose of the SPS. This requirement should be applied uniformly to all SPS types. The time
required to review each SPS operation will vary with the complexity of the SPS.
The analysis of each operation should include:
•
The power system conditions which triggered the SPS.
•
A determination of whether or not the SPS responded as designed.
•
An analysis of the power system response to the SPS operation.
•
An analysis of the effectiveness of the SPS in mitigating power system issues it was designed to address. This
analysis should identify whether or not those issues existed or were likely to occur at the time of the SPS
operation.
•
Any unintended or adverse power system response to the SPS operation.
For each SPS operation, the analysis should identify the power system conditions which existed at the time of the SPS
operation. These conditions should be analyzed to determine whether or not the SPS operation was appropriate. This part
of the analysis is to determine both whether or not the SPS operated as designed, and whether or not the conditions the
SPS is intended to mitigate were present at the time of SPS operation.
Some SPS use a proxy to determine the possible existence of a system problem. For example, the opening of a generator
outlet may cause an overload remote from the generator. An SPS could monitor the status of the outlet and run back
generation to avoid the possible overload, rather than monitoring the loading on the potentially impacted element. The
analysis should determine whether the SPS responded to the loss of outlet, and whether the overload actually would have
occurred without SPS operation.
The analysis should also examine the response of the system to the SPS operation. This part of the analysis is to determine
whether or not the SPS is effective in its intended mitigation, and if it has unforeseen adverse or unnecessary impacts on
the power system.
As noted with the proposed definition above, the reporting requirements for each SPS misoperation should vary based on
the attributes of the misoperation. The following discussion proposes reporting requirements and provides rationale for the
type of SPS misoperation to which each should apply.
1.
The SPS owner should be required to provide analysis of the misoperation to its Reliability Coordinator and
Planning Coordinator for all SPS misoperations. The report should be provided to the Reliability Coordinator and
the Planning Coordinator because such misoperations may require a reevaluation of the SPS under the review
process proposed in the Study and Documentation Requirements section. The report should include the corrective
action to assist the Reliability Coordinator and Planning Coordinator in confirming whether the SPS requires
reevaluation.
2.
The SPS owner should be required to develop and implement a corrective action plan for all SPS misoperations.
Reporting details of the corrective action plan should be limited to purposes supporting reliability. As noted above,
the report to the Reliability Coordinator and Planning Coordinator should include corrective actions. If an SPS must
be removed from service or its operation is modified pending implementation of the corrective action plan, the
status must be reported to the Reliability Coordinator, Transmission Operator, or Balancing Authority.
3.
The SPS owner should be required to report for reliability metric purposes any SPS misoperation that involves a
failure to operate or unnecessary operation. These attributes are analogous to protection system misoperations
that must be reported and involve a failure of the SPS to operate per its installed design. The mechanism for
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Chapter 5 – Analysis of SPS Operations
requiring reporting for reliability metric purposes should be similar to the process for reporting protection system
misoperations under development in Project 2010-05.1: Protection Systems: Phase 1 (Misoperations).
4.
The SPS owner should not be required to report or develop corrective action plans for other failures associated
with an SPS that are not associated with an SPS operation or failure to operate, such as:
•
Failure to Arm – Any failure of a SPS to automatically arm itself for system conditions that are intended to
result in the SPS being automatically armed;
•
Unnecessary Arming – Any automatic arming of a SPS that occurs without the occurrence of the intended
arming system condition(s); and
•
Failure to Reset – Any failure of a SPS to automatically reset following a return of normal system conditions, if
the system design requires automatic reset.
These types of failures can be corrected by the SPS owner without involving the Reliability Coordinator and the
Planning Coordinator, and are analogous to a protection system owner identifying a failed power supply on a relay. If
the failure has not resulted in a misoperation then reporting and corrective action plans are not required. It should be
noted however, that operational requirements apply and if an SPS must be removed from service the status must be
reported to the Reliability Coordinator, Transmission Operator, or Balancing Authority.
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Chapter 6 – Recommendations
Definition
The existing SPS definition in the NERC glossary lacks clarity and specificity necessary for consistent identification and
classification of SPS. The following strawman definition is proposed.
Special Protection System
A scheme designed to detect predetermined system conditions and automatically take corrective actions,
other than the isolation of faulted elements, to meet system performance requirements identified in the
NERC Reliability Standards, or to limit the impact of: two or more elements removed, an extreme event,
or Cascading.
Subject to the exclusions below, such schemes are designed to maintain system stability, acceptable
system voltages, acceptable power flows, or to address other reliability concerns. They may execute
actions that include but are not limited to: changes in MW and Mvar output, tripping of generators and
other sources, load curtailment or tripping, or system reconfiguration.
The following schemes do not constitute an SPS in and of themselves:
a)
Underfrequency or undervoltage load shedding
b) Locally sensing devices applied on an element to protect it against equipment damage for nonfault conditions by tripping or modifying the operation of that element, such as, but not limited
to, generator loss-of-field or transformer top-oil temperature
c)
Autoreclosing schemes
d) Locally sensed and locally operated series and shunt reactive devices, FACTS devices, phaseshifting transformers, variable frequency transformers, generation excitation systems, and tapchanging transformers
e)
Schemes that prevent high line voltage by automatically switching the affected line
f)
Schemes that automatically de-energize a line for non-fault operation when one end of the line is
open
g)
Out-of-step relaying
h) Schemes that provide anti-islanding protection (e.g., protect load from effects of being isolated
with generation that may not be capable of maintaining acceptable frequency and voltage)
i)
Protection schemes that operate local breakers other than those on the faulted circuit to
facilitate fault clearing, such as, but not limited to, opening a circuit breaker to remove infeed so
protection at a remote terminal can detect a fault or to reduce fault duty
j)
Automatic sequences that proceed when manually initiated solely by an operator
k)
Sub-synchronous resonance (SSR) protection schemes
l)
Modulation of HVdc or SVC via supplementary controls such as angle damping or frequency
damping applied to damp local or inter-area oscillations
m) A Protection System that includes multiple elements within its zone of protection, or that isolates
more than the faulted element because an interrupting device is not provided between the
faulted element and one or more other elements
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Chapter 6 – Recommendations
Classification
SPS should be classified based on the type of event to which the SPS responds and the consequence of misoperation.
Classification of SPS facilitates standard requirements commensurate with potential reliability risk. Four classifications are
proposed:
•
Type PS: planning – significant,
•
Type PL: planning – limited,
•
Type ES: extreme – significant, and
•
Type EL: extreme – limited.
The planning classification applies to schemes designed to meet system performance requirements identified in the NERC
Reliability Standards, while the extreme classification applies to schemes designed to limit the impact of two or more
elements removed, an extreme event, or Cascading.
The significant classification applies to a scheme for which a failure to operate or inadvertent operation of the scheme can
result in non-consequential load loss greater than or equal to 300 MW, aggregate resource loss (tripping or runback of
generation or HVdc) greater than the largest Real Power resource within the interconnection, loss of synchronism between
two portions of the system, or negatively damped oscillations. The limited classification applies to a scheme for which a
failure to operate or inadvertent operation would not result in a significant impact.
Applicability to Functional Model Entities
Three of the existing SPS-related reliability standards (PRC-012-0, PRC-013-0, and PRC-014-0) assign requirements to the
Regional Reliability Organization. These standards are not mandatory and enforceable because FERC identified them as fillin-the-blank standards in Order No. 693. This report recommends that requirements be reassigned to users, owners, and
operators of the bulk power system in accordance with the NERC Functional Model. The following recommendations are
included in the report:
•
Review of new or modified SPS – assign to Reliability Coordinators and Planning Coordinators.
•
SPS database maintenance – assign to Planning Coordinators; have Planning Coordinators submit databases to
NERC for maintenance of a continent-wide database.
•
Assessment of existing SPS – assign Planning Coordinators and Transmission Planners responsibility to include SPS
assessments in annual transmission planning assessments; assign Reliability Coordinators responsibility to
coordinate a periodic assessment of SPS design and coordination.
Revisions to Reliability Standards
Figure 1 provides a high-level overview of recommendations related to the six PRC standards that apply to SPS.
Recommendations include consolidating the six existing standards into three standards.
•
Combine all requirements pertaining to review, assessment, and documentation of SPS (presently in PRC-012-0,
PRC-013-0, PRC-014-0, and PRC-015-0) in one new standard, PRC-012-1. The requirement in PRC-012-0 for regional
procedures for reviewing SPS misoperations is superseded by recommendations for revisions to PRC-016-0.1. The
requirement in PRC-012-0 for regional maintenance and testing requirements is superseded by PRC-005-2.
•
Requirements pertaining to analysis and reporting of SPS misoperations should be revised in a new standard, PRC016-1. Due to the significant difference between protection systems and SPS, the subject of SPS misoperations
should not be included in a future revision of PRC-004.
•
Requirements pertaining to maintenance and testing of SPS already have been translated to PRC-005-2 by the
Project 2007-17 Protection System Maintenance & Testing drafting team.
Additional detail is provided in Table 2 in Appendix C – Mapping of Requirements from Existing Standards. This table
summarizes the recommendations for how each requirement in the existing six SPS-related standards should be mapped to
revised standards. The more significant recommendations are summarized below.
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Chapter 6 – Recommendations
PRC-012-0
RRO
Review Procedure
PRC-013-0
RRO
Database
PRC-014-0
RRO
Assessment
PRC-015-0
SPS Owner
•Change applicability to RC and PC
•Establish a uniform continent-wide SPS
review procedure
•Eliminate regional procedures for SPS
misoperations; address in PRC-016-1
•Change applicability to PC
•Establish continent-wide data requirements
•Require PC to submit database to NERC to
establish a continent-wide database
PRC-012-1
RC, PC, TP, and
SPS Owner
•Change applicability to PC and TP for annual
assessment and RC for five-year assessment
•Expand assessment requirements for
coordination of SPS and protection systems
Review, Assessment,
and Documentation
•Keep applicable to SPS owner
•Develop detailed list of data that SPS
owners must submit
Data & Documentation
PRC-016-0.1
SPS Owner
Misoperations
PRC-017-0
SPS Owner
Maintenance & Testing
•Keep applicable to SPS Owner
•Continent-wide definition of SPS
misoperation
•Continent-wide requirements for analysis
and reporting
PRC-016-1
•Keep applicable to SPS owner
•Requirements mapped to PRC-005-2
•Recommend additional requirements to
address complexity of SPS and nonprotection system components used in SPS
PRC-005-2
SPS Owner
Misoperations
SPS Owner
Maintenance & Testing
Figure 1 – Recommended Mapping of Existing PRC Standards
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Chapter 6 – Recommendations
Standard PRC-012-1 – SPS Review, Assessment, and Documentation
•
SPS owners should be required to design Type PL and Type PS SPS so that a single SPS component failure does not
prevent the interconnected transmission system from meeting the performance requirements defined in NERC
Reliability Standards TPL-001-0, TPL-002-0, or TPL-003-0.
•
Existing requirements for regional procedures for reviewing new or modified SPS should be replaced with a
continent-wide procedure assigned to Reliability Coordinators and Planning Coordinators to assure a wide-area
view of both planning and operational aspects of SPS.
•
Annual transmission planning assessments should include an assessment by the Planning Coordinator and
Transmission Planner to review the operation, coordination, and effectiveness of SPS, including the effect of
correct operation, a failure to operate, and inadvertent operations.
•
Periodic comprehensive assessments (every five years or less) of SPS should be performed by the Reliability
Coordinator, with support as requested from other entities, to assess whether SPS are still necessary, serves their
intended purpose, meet relevant design criteria, coordinate with other SPS, UFLS, UVLS, and protection systems,
and do not have unintended adverse consequences on reliability.
•
Detailed continent-wide requirements for data submittals should be established for SPS owners proposing new or
modified SPS. Detailed recommendations are included in this report.
•
Planning Coordinators should be assigned responsibility for maintaining databases containing all information
submitted by SPS owners. Planning Coordinators should be required to submit their databases to NERC so that
NERC can maintain and make available a continent-wide SPS database.
Standard PRC-016-1 – SPS Misoperations
•
PRC-016-1 should include a continent-wide definition of SPS misoperation based on the strawman definition
proposed in this report.
•
PRC-016-1 should include a continent-wide process for analysis of SPS operations and reporting SPS misoperations,
including requirements for SPS owners to develop corrective action plans and provide analysis of SPS
misoperations to Reliability Coordinators and Planning Coordinators.
•
Reporting SPS operation and misoperation data for reliability metric purposes should be addressed outside PRC016-1, in a manner similar to the process under development for reporting protection system misoperations in
Project 2010-05.1 Protection Systems: Phase 1 (Misoperations).
Standard PRC-005-2 – Protection System Maintenance and Testing
•
Maintenance and testing requirements for SPS should be expanded in the NERC Reliability Standards to address
the complexity of testing SPS and the maintenance of non-protection system components used in SPS. These
subjects should be addressed in a future revision of PRC-005 or development of a separate standard.
Recommendations to Be Included in Other Standards
This report discusses some aspects of SPS that are not addressed in the six SPS-related PRC standards. Recommendations
should be incorporated in appropriate NERC Reliability Standards.
•
SPS owners should be required to provide disturbance monitoring equipment to permit analysis of SPS
performance following an event.
•
Operating entities should be required to provide operators with documentation of procedures for operator
interaction with SPS, and how operators should respond to SPS failures.
•
All SPS should be monitored by SCADA/EMS with real-time status communicated that minimally includes whether
the scheme is in-service, out-of-service, and the current operational state of the scheme.
•
One entity should be assigned responsibility for monitoring, coordination, and control of an SPS.
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Appendix A – Modeling and Simulation Considerations
The addition of two stable control systems does not necessarily result in a stable composite control system; the same is
true for SPS. Although the SPS may not be directly linked in their actions, their composite actions and effect on the electric
system for commonly-sensed system conditions or perturbations can often behave as a single control system. Therefore, it
is imperative that they be evaluated for their potential to interact with each other, particularly during a system disturbance.
The composite interaction of multiple SPS, or of SPS with UFLS, UVLS, or other protection systems could result in system
instability or cascading.
Because of the complexity of some schemes, modeling them in system simulation is currently performed most often by
monitoring their trigger conditions and manually mimicking their intended actions such as changing system configuration,
switching reactive devices, and adjusting or tripping generation. Such manual manipulations in powerflow and dynamics
studies are only effective when studying a single SPS unless an iterative process is used. Even then, manual manipulation
may not be effective and may not be possible in studying the simultaneous actions of multiple SPS that could potentially
interact with each other. The difficulty is most significant when considering the potential interaction of parameter-based
SPS, since interaction with event-based SPS would occur only if the initial event and SPS operation caused a second event to
occur.
It is sometimes possible to simulate the behavior of a single SPS through simulation tools such as user-defined scripts using
vendor-provided or open-source programming capability, or standard relay models in the typical modeling and simulation
software packages. However, doing so for the myriad of SPS that may exist, even in a portion of an interconnection, is
cumbersome. Furthermore, simulating multiple SPS in real-time operations tools (e.g., EMS) for real-time contingency
analysis is extremely difficult and often requires new and innovative algorithm and software development. In addition,
models used in real-time systems are often abridged or reduced equivalents and may not permit accurate representation of
a particular SPS’s functions. All of these issues are extremely problematic given the sheer number of SPS in North American
interconnections.
To assure SPS will function in a coordinated fashion may require that they be modeled and studied from their design
inception in the planning horizon, through pre-seasonal system studies that determine transfer capabilities, and in the
operating horizon from day-ahead planning through the real-time contingency analysis that system operators depend on
for guidance. Present analysis methods are limited by the capability of the software tools and management of the SPS, and
in some cases protection system, data. The industry should put emphasis on future developments in these areas.
General Considerations for Simulations
This section puts forth a number of factors, limitations, objectives, and overall guiding principles that a standard drafting
team should consider in development of a new SPS standard with respect to the requirements for modeling and simulation,
including data and process requirements necessary to support accurate and meaningful studies of SPS by Transmission
Planners.
This report assumes that the modeling and simulation activities to be addressed are those performed for the planning
horizon by Transmission Planning personnel. It is assumed that studies are performed using commercial off-the-shelf
software packages and using databases derived from the interconnection-wide series of powerflow and dynamics cases.
Studies using EMS based tools (e.g., study tools built into state estimators, real-time contingency analysis software, etc.) for
real-time operations are not within the scope of this appendix.
It is important however, that the Transmission Planner share the results of planning horizon studies with operations
personnel such that the impacts of SPS are effectively understood for the operating horizon also. This can be accomplished
in a number of ways. Where operations support staff have similar study tools, sharing of the powerflow/dynamics cases,
models, simulation scripts and similar data would enable them to evaluate SPS operation (or misoperation) for the
operating horizon. Providing alarm or action limits for observable parameters (i.e., those that could be monitored in the
operating environment) related to SPS operation would be another possibility. In this case, the parameters may be a direct
indication or a proxy value that is indicative of the system condition of concern. Regardless of the process employed, the
overriding consideration is that study results are adequately translated into actionable intelligence that is available to and
understood by the system operator. While this is not intended to create a recommendation for a specific SPS standard
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Appendix A – Modeling and Simulation Considerations
requirement, how this would ultimately be accomplished should be kept in mind as SPS standards are developed and
implemented.
As a general rule, SPS are conceived by transmission planning engineers and implemented by protection and control
engineers. To some extent, the engineers in these two groups are concerned with different aspects of SPS operation and
use different terminology to describe SPS (and other system) functions. For example, a transmission planner may consider a
protection system component failure to be a contingency while a protection engineer may consider this to be a design
consideration. Transmission planning engineers conceive an SPS as a solution to system-level problems. Their focus is on
the “big picture” functional operation of the SPS for specific system level conditions. Protection and control engineers
implement an SPS via detailed design using various sensors, relays, etc. Their focus is on efficiently implementing the
functional requirements as they understand them to be. It is imperative that the planning engineers effectively
communicate the requirements of the SPS to protection engineers and monitor the design and implementation of the
scheme to ensure that the SPS is implemented and functions as prescribed by the planner.
The planning and protection engineers should also consult with the operations personnel to ensure that possible systemlevel events which might result in unintended SPS operation are considered. Involving operations personnel at each stage of
the design process will help ensure that the range of operating conditions likely to be encountered in the real world
(including outages), as well as practical operating considerations, are also adequately considered in the SPS design and
implementation.
An explicit requirement should exist to represent the salient features of SPS operation in a form that can be readily shared
with, understood by, and used in simulations by other Transmission Planners. Simulation of SPS in powerflow or dynamic
studies may involve a combination of using standard relay models, various monitoring features, and scripts or program
code to adequately simulate the functioning of the SPS. These may include user-defined scripts using vendor-provided or
open-source programming capability, or standard relay models in the typical modeling and simulation software packages
(either executed during solution-run time or as user-written dynamic models), etc. Transmission Planners generally have
their own individual preferences as to how to reflect these functions when performing simulations. Additionally, different
Transmission Planning organizations have different levels of expertise in developing scenarios to reflect actual system
operation and performing simulations based on those scenarios. Therefore, it is important that the modeling information to
be used by other Transmission Planning engineers as input (including run scripts) in simulations be simple, understandable
and well documented. Any scripts or models provided need to be “open source” in nature and well-documented to enable
independent verification. The use of user models, FORTRAN object code, compiled scripts, and similar which make it
difficult for the receiving Transmission Planner to review and understand how the SPS model functions must be avoided.
In addition to providing the relay models, program code/script, and similar input as part of the database, a summary
document should be provided explaining the SPS. The information shared must include a summary and guidance document
which includes the following, as applicable.
•
An overview explanation of the basic functioning of the SPS, describing when and how it operates
•
A listing of the setpoints applicable to the SPS (e.g., relay trip settings, etc.)
•
A summary overview of how the SPS is being simulated via relay models, simulation scripts that may be provided
•
Specific bus numbers, branch identifiers, machine identifiers, etc. should be referenced to help the Transmission
Planner receiving this information understand how the SPS is being simulated
SPS modeling information should be readily available as part of the interconnection-wide modeling processes, but not an
integral part of an interconnection-wide case year database. Specific recommendations are included in the chapter on study
and documentation requirements.
Because of the special nature of SPS, it is not practical or even possible to include them in the interconnection-wide load
flow and/or dynamic database case years in the classic sense (e.g., such as one would include a generator or FACTS device
model). Additionally, it is simply not necessary to model all SPS for all simulations. The reality is that an SPS in the Northeast
will likely have very little impact on the results of simulations focused on the Southeast. Therefore, including all SPS in all
simulations places an unreasonable burden on Transmission Planners. However, due consideration should be given to the
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Appendix A – Modeling and Simulation Considerations
interaction of a given SPS with other SPS. Note that geographical distance alone may not be sufficient justification not to
consider the interaction of several SPS.
However, it is important that information about all SPS be available for use, as deemed appropriate by the Transmission
Planners whose systems may be affected by the SPS operation (or misoperation). It is also important the relevant
parameter-based SPS be modeled concurrently in simulations to appropriately evaluate potential interactions among the
SPS.
Therefore, the data management process for providing SPS information for simulations purposes should include the
following considerations.
•
Sufficiently detailed SPS information and documentation as described above can be managed as part of the
interconnection-wide powerflow and dynamic case creation process.
•
Providing the models and simulation scripts alone is not sufficient. A functional description to assist the
Transmission Planner in understanding how these modeling/simulation elements work to emulate the SPS function
is necessary in order for the Transmission Planner to properly simulate and interpret the results of simulations
involving the SPS.
•
The SPS information may reside separately from the interconnection-wide powerflow and dynamic cases, but a
clear association to each case must be evident.
•
Each Transmission Planner will be able to select the SPS that are relevant to the simulation they are performing.
Engineering judgment, with a documented reason, for excluding SPS from simulations is acceptable.
•
Where included, the impact of multiple SPS and their interaction should be reasonably accounted for in the
simulation activities.
It is envisioned that Transmission Planners will generally include only those SPS that, in their judgment, are relative to the
simulations being performed and/or could potentially interact with other SPS being included in these simulations. However,
it would be prudent to have some big picture check for unintended SPS interaction. Therefore, a joint, interconnection-wide
study or assessment should be periodically performed to evaluate potential interactions among SPS across the entire
interconnection. Such a study or assessment should include modeling and simulation of all of the SPS throughout the
interconnection. A periodicity of five years for this joint study is suggested as an appropriate time frame.
Use of SPS Simulations in Transmission Planning Studies
SPS are used as alternatives to transmission infrastructure to support reliable system operation for identified concerns. As
such, these schemes must be analyzed in transmission planning analyses just as any other transmission system addition
would be, with a focus on:
•
Operation as expected for the design case of concern
•
Understanding the potential for operation beyond the original design intent
•
Determining if there is a potential for failure to operate to rectify the design case of concern.
In system planning, the types of studies which are typically performed to determine system performance are powerflow
and dynamic simulations and analyses. SPS need to be modeled in both of these types of studies.
Powerflow (i.e., steady-state) SPS modeling techniques which could be employed include:
•
Explicit modeling of the SPS monitoring and consequent actions with scripting and programming automatically
called during powerflow processing
•
Explicit modeling of the actuation of the SPS in contingencies which are expected to cause the SPS to actuate
•
Contingencies are included in the analysis with and without the SPS actuated
•
Monitoring of system performance to determine if system conditions would actuate an SPS
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Appendix A – Modeling and Simulation Considerations
o
The monitoring occurs for all contingencies examined
o
Any result indicating potential actuation of an SPS is rerun with the SPS actuated
Dynamic (i.e., stability) SPS modeling techniques which could be employed include:
•
Explicit modeling of the SPS in the dynamic simulation with a model that includes the monitoring and consequent
actions during the dynamic simulations
•
Explicit modeling of the actuation of the SPS in contingencies which are expected to cause the SPS to actuate
•
The dynamic/stability contingencies are included in the analysis with and without the SPS actuated
•
Monitoring of SPS trigger elements (voltage, current, flow and/or frequency on system elements or element
status) to determine if actuation of an SPS would have actuated
o
Rerun the simulation with the SPS actuated if the monitored results indicate potential actuation of the SPS
The SPS modeling techniques used in system planning should be based upon modeling information provided by the SPS
owner which clearly describes what the SPS senses and the consequent actions taken when its triggering needs are met.
The need for accurate modeling information can be demonstrated with an example. In the example, two SPS exist in an
area. One SPS trips a large generating plant for loss of a transmission circuit due to first swing stability concerns. This SPS
acts within cycles of the initiating line loss. The second SPS inserts a series reactor into a transmission circuit to limit flow
and eliminate an overload on the circuit. The second SPS acts within seconds (5 seconds for this example) of the overload
condition occurring.
Steady state studies of the area where these SPS exist would examine the representative cases (sets of system conditions)
and contingency sets for the study in question. If the power flow software allowed, a post-solution program could be run to
test if the actuating circumstances for each SPS were met; if so, the contingent solution would be rerun and tested again for
any other SPS which would actuate. If the power flow software did not have this flexibility, the engineer could include an
SPS actuation for those contingencies expected to trigger the SPS and run that expanded contingency list; the results could
be examined with attention paid to the loading for the circuit protected by the second SPS. Any contingencies which caused
an overload on the triggering circuit could be rerun with the SPS actuated.
Since both SPS act within the dynamic simulation timeframe, the SPS should be modeled or monitored in stability
simulations. Dynamic models could exist for both SPS. Should the flow on the SPS-triggering line exceed the flow actuation
setpoint for the required time duration, the dynamic simulation would capture the impact of the reactor insertion and the
SPS actuation. If the SPS were not explicitly modeled, their trigger values could be monitored (i.e., the status or flow on the
line for the first SPS and the flow on the potentially overloaded circuit for the second SPS). The monitored data channels
would be examined after each simulation to determine if the simulation needed to be rerun while modeling the
appropriate SPS actions.
The goal for modeling SPS in studies is to confirm that they will operate to correct the intended system concerns as
necessary to preserve acceptable system performance. In addition, the analyses provide understanding for system planning
and operations on when and how the use of the SPS may change over time. This information may be critical for system
operations staff to maintain reliable system operation.
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Appendix B – Operational Considerations
This information is a high level list of important issues and concerns if performing SPS analyses in real-time operations.
Real-time SPS Evaluation
Current system conditions must be identified before evaluating whether an SPS would perform its function and achieve its
desired outcome. Results of security analysis should be required to indicate whether an SPS should be armed (if armed
manually) and whether an SPS will operate for a given contingency. Security analysis should model operation of the SPS in
addition to the initiating contingency when the SPS is armed.
SPS evaluation often cannot be done with SCADA input alone. Some non-SCADA input may be needed; for example, limits
from off-line studies are converted into inputs available in the Energy Management System (EMS). The inputs that support
SPS evaluation and operation need to be codified in operating guides and presented on operator displays for ease of use
and operation. Custom code and displays are generally required to aggregate all needed information for usage by engineers
and operators in real time.
The impact of SPS operation on facilities external to the SPS owner/operator needs to be jointly considered and
communicated to external entities and appropriately accounted for in EMS. Furthermore, the effects of external
contingencies on the SPS triggers should be accounted for within EMS and known to operators.
SPS evaluation typically involves the testing of a limited set of relevant contingencies, requiring the use Real-Time
Contingency Analysis (RTCA). In some cases, a dc solution to identify thermal issues is adequate; in other cases, a full ac
solution is required (e.g., where triggers are voltage dependent).
Some EMS are not robust enough to compute ac solutions in EMS/RTCA. Depending on the classification of an SPS (e.g.,
significant), an EMS/RTCA with such limited capability would be insufficient to evaluate the impact of the SPS. In such cases
it is necessary to establish other means, such as supplemental off-line tools or delegation of this analysis to an entity that
has this capability, to study the operational impacts of the SPS.
If the EMS/RTCA does not reach a solved state, then the SPS cannot be evaluated. For example, some EMS/RTCA will fail to
solve or fail to converge upon the creation of islands in the model. In these cases, SPS modeling may require custom
software solutions.
Multiple Decision-Making Capability
When evaluating SPS in EMS/RTCA, intermediate steps must be modeled and intermediate states must be evaluated. It
should be assumed that an SPS may suffer a full or partial failure and that system conditions will change as the SPS
operates. Adverse conditions may arise during intermediate steps that lead to undesired outcomes or put the system into
an unplanned operating state.
The post-contingency, pre-SPS-operation state must be known to assess system conditions before the SPS action can be
evaluated. For example, the loss of a large nuclear station automatically activates a large emergency core cooling load. This
new system state would require a re-solution to check post-contingent node voltage (i.e., with the load connected) before
consideration of SPS activation and results can occur. This requires that several stages and intermediate actions be modeled
in the evolution of the final system topology to ensure that the system can reach the desired end-state.
Information Management
Each SPS may have its own set of arming and activation triggers. Examples include equipment status, line loading and
voltage. These triggers may be complex, and could affect the alarming capability required of EMS.
Changes to EMS models may require long lead times before an SPS can be implemented; for example, changes to models
often require pushing through multiple staged software environments. Entities should use software designs that are flexible
to accommodate timely changes to SPS models that might not be tied to the network model database release schedule.
When implementing an SPS before the EMS model can be updated, it is necessary to establish other means, such as
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Appendix B – Operational Considerations
supplemental off-line tools or delegation of this analysis to an entity that has this capability, to study the operational
impacts of the SPS.
Modeling Simplicity and Usability
Complex SPS schemes require due diligence to maintain and support. Entities should be required to develop and document
an efficient approach to SPS control. An entity’s strategy should allow for concurrent and/or consecutive SPS actions.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-012-0
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning
to use an SPS shall have a documented
Regional Reliability Organization SPS review
procedure to ensure that SPSs comply with
Regional criteria and NERC Reliability
Standards. The Regional SPS review
procedure shall include:
PRC-012-1 should define a continent-wide SPS
review procedure conducted by the Reliability
Coordinator and Planning Coordinator.
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-012-0
R1.1. Description of the process for
submitting a proposed SPS for
Regional Reliability Organization
review.
PRC-012-1 should define a continent-wide SPS
review procedure conducted by the Reliability
Coordinator and Planning Coordinator.
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-012-0
R1.2. Requirements to provide data that
describes design, operation, and
modeling of an SPS.
PRC-012-1 should define continent-wide
requirements for SPS owners to provide data that
is clear and understandable to all entities that
require this information to plan and operate the
bulk power system.
See Data Submittals by Entities that Own SPS on
pp. 18-19.
PRC-012-0
R1.3. Requirements to demonstrate that the
SPS shall be designed so that a single
SPS component failure, when the SPS
was intended to operate, does not
prevent the interconnected
transmission system from meeting
the performance requirements
defined in Reliability Standards TPL001-0, TPL-002-0, and TPL-003-0.
PRC-012-1 should require that all Type PS and PL
SPS are designed so system performance
requirements are met in the event of a single
component failure within the SPS.
See SPS Single Component Failure Requirements
on p. 14-15
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
PRC-012-0
PRC-012-0
PRC-012-0
PRC-012-0
Requirement
Proposal
Comments
PRC-012-1 should require that an entity proposing
a new or modified SPS should be required to
submit studies that demonstrate the operation,
coordination, and effectiveness of the SPS,
including the impacts of a correct operation, a
failure to operate, and inadvertent operation.
See Review and Approval of New or Modified SPS
on p. 16.
R1.5. Requirements to demonstrate the
proposed SPS will coordinate with
other protection and control systems
and applicable Regional Reliability
Organization Emergency procedures.
PRC-012-1 should require that an entity proposing
a new or modified SPS should be required to
submit studies that demonstrate the operation,
coordination, and effectiveness of the SPS,
including the impacts of a correct operation, a
failure to operate, and inadvertent operation.
See Review and Approval of New or Modified SPS
on p. 16.
R1.6. Regional Reliability Organization
definition of misoperation.
A continent-wide definition of an SPS
misoperation should be established.
See SPS Misoperation Definition on p. 22.
Do not carry forward to revised standards.
The need for this requirement is eliminated by
establishing continent-wide requirements in PRC016-1. See SPS Operation Review Process on pp.
23-24.
R1.4. Requirements to demonstrate that the
inadvertent operation of an SPS shall
meet the same performance
requirement (TPL-001-0, TPL-002-0,
and TPL-003-0) as that required of the
contingency for which it was
designed, and not exceed TPL-003-0.
R1.7. Requirements for analysis and
documentation of corrective action
plans for all SPS misoperations.
PRC-012-0
R1.8. Identification of the Regional Reliability
Organization group responsible for
the Regional Reliability Organization’s
review procedure and the process for
Regional Reliability Organization
approval of the procedure.
Do not carry forward to revised standards.
The need for this requirement is eliminated by
establishing a continent-wide review procedure
within PRC-012-1. See Review and Approval of
New or Modified SPS on pp. 16-17.
PRC-012-0
R1.9. Determination, as appropriate, of
maintenance and testing
requirements.
Do not carry forward to revised standards.
The need for this requirement is eliminated by
establishing continent-wide maintenance and
testing requirements within PRC-005-2.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-012-0
R2. The Regional Reliability Organization shall
provide affected Regional Reliability
Organizations and NERC with documentation
of its SPS review procedure on request
(within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-013-0
R1. The Regional Reliability Organization that has
a Transmission Owner, Generator Owner, or
Distribution Provider with an SPS installed
shall maintain an SPS database. The database
shall include the following types of
information:
PRC-012-1 should require that each Planning
Coordinator maintain a database, and provide the
database to NERC for the purpose of maintaining
a continent-wide database.
See SPS Database on p. 19.
PRC-013-0
R1.1. Design Objectives — Contingencies and
system conditions for which the SPS
was designed,
This information is included in a comprehensive
list of data requirements to be provided by the
SPS owner and maintained in a database by the
Planning Coordinator.
See Data Submittals by Entities that Own SPS on
pp. 18-19 and SPS Database on p. 19.
PRC-013-0
R1.2. Operation — The actions taken by the
SPS in response to Disturbance
conditions, and
This information is included in a comprehensive
list of data requirements to be provided by the
SPS owner and maintained in a database by the
Planning Coordinator.
See Data Submittals by Entities that Own SPS on
pp. 18-19 and SPS Database on p. 19.
PRC-013-0
R1.3. Modeling — Information on detection
logic or relay settings that control
operation of the SPS.
This information is included in a comprehensive
list of data requirements to be provided by the
SPS owner and maintained in a database by the
Planning Coordinator.
See Data Submittals by Entities that Own SPS on
pp. 18-19 and SPS Database on p. 19.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-013-0
R2. The Regional Reliability Organization shall
provide to affected Regional Reliability
Organization(s) and NERC documentation of
its database or the information therein on
request (within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-014-0
R1. The Regional Reliability Organization shall
assess the operation, coordination, and
effectiveness of all SPSs installed in its Region
at least once every five years for compliance
with NERC Reliability Standards and Regional
criteria.
PRC-012-1 should require the Planning
Coordinator and Transmission Planner to assess
SPS in annual transmission planning assessments
and require the Reliability Coordinator to conduct
a periodic review every five years, or sooner if
significant changes are made to the system
topology or operating characteristics that may
impact the coordination among SPS and between
SPS and UFLS, UVLS, and other protection
systems.
See Periodic Comprehensive Assessments of SPS
Coordination on p. 17.
PRC-014-0
R2. The Regional Reliability Organization shall
provide either a summary report or a
detailed report of its assessment of the
operation, coordination, and effectiveness of
all SPSs installed in its Region to affected
Regional Reliability Organizations or NERC on
request (within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-014-0
R3. The documentation of the Regional Reliability
Organization’s SPS assessment shall include
the following elements:
PRC-012-1 should require the Reliability
Coordinator to document its periodic
assessments. The documentation should include
the same elements required in a study supporting
approval of a new or modified SPS.
See Review and Approval of New or Modified SPS
on pp. 16-17 and Assessment of Existing SPS on p.
17.
This list of elements includes:
• Entity conducting the study
• Study completion date
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-014-0
R3.1. Identification of group conducting the
assessment and the date the
assessment was performed.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-014-0
R3.2. Study years, system conditions, and
contingencies analyzed in the
technical studies on which the
assessment is based and when those
technical studies were performed.
This list of elements includes:
• Study years
• System conditions
• Contingencies analyzed
• Study completion date
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-014-0
R3.3. Identification of SPSs that were found
not to comply with NERC standards
and Regional Reliability Organization
criteria.
PRC-012-1 should require the Planning
Coordinator and Transmission Planner document
and submit any issues identified in the annual
assessment to the Reliability Coordinator.
PRC-012-1 should require the Reliability
Coordinator to document and submit any issues
identified in the periodic assessment to the SPS
owner.
See Assessment of Existing SPS on p. 17.
PRC-014-0
R3.4. Discussion of any coordination
problems found between a SPS and
other protection and control systems.
PRC-012-1 should require the Reliability
Coordinator to request the Planning Coordinator
and Transmission Planner to assess and document
whether the SPS is still necessary, serves its
intended purpose, meets performance criteria,
coordinates with other SPS, UFLS, UVLS, and
protection systems, and does not have
unintended adverse consequences on reliability.
See Periodic Comprehensive Assessments of SPS
Coordination on p. 17.
PRC-014-0
R3.5. Provide corrective action plans for noncompliant SPSs.
PRC-012-1 should require that if issues are
identified in an annual or periodic assessment,
the Reliability Coordinator and Planning
Coordinator determine, in consultation with the
SPS owner, whether a corrective action plan is
required, and if so, whether the SPS can remain in
service until a corrective action plan is
implemented.
If a corrective action plan is required, PRC-012-1
should require the SPS owner to submit an
application for a new or modified SPS.
See Assessment of Existing SPS on p. 17.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-015-0
R1. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall maintain a list of and provide data for
existing and proposed SPSs as specified in
Reliability Standard PRC-013-0_R1.
PRC-012-1 should define continent-wide
requirements for SPS owners to provide data that
is clear and understandable to all entities that
require this information to plan and operate the
bulk power system.
See Data Submittals by Entities that Own SPS on
pp. 18-19.
PRC-015-0
R2. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall have evidence it reviewed new or
functionally modified SPSs in accordance with
the Regional Reliability Organization’s
procedures as defined in Reliability Standard
PRC-012-0_R1 prior to being placed in
service.
Do not carry forward to revised standards. PRC012-1 should have a requirement for the SPS
owner to file an application for approval of an
SPS, which assures that the SPS is reviewed in
accordance with the continent-wide review
procedure prior to being placed in service.
See Review and Approval of New or Modified SPS
on pp. 16-17.
PRC-015-0
R3. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall provide documentation of SPS data and
the results of Studies that show compliance
of new or functionally modified SPSs with
NERC Reliability Standards and Regional
Reliability Organization criteria to affected
Regional Reliability Organizations and NERC
on request (within 30 calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-016-0.1
R1. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall analyze its SPS operations and maintain
a record of all misoperations in accordance
with the Regional SPS review procedure
specified in Reliability Standard PRC-0120_R1.
PRC-016-1 should establish a continent-wide
process for analyzing and reporting SPS
misoperations.
See SPS Operation Review Process on pp. 23-24.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
Requirement
Proposal
Comments
PRC-016-0.1
R2. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall take corrective actions to avoid future
misoperations.
PRC-016-1 should establish a requirement that
the SPS owner should be required to develop and
implement a corrective action plan for SPS
misoperations.
See SPS Operation Review Process on pp. 23-24.
PRC-016-0.1
R3. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall provide documentation of the
misoperation analyses and the corrective
action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
Do not carry forward to revised standards.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
R1. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall have a system maintenance and testing
program(s) in place. The program(s) shall
include:
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Tables 1-1 – 1-5, and Table 2.
PRC-017-0
PRC-017-0
21
R1.1. SPS identification shall include but is
not limited to:
PRC-017-0
R1.1.1. Relays.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-1.
PRC-017-0
R1.1.2. Instrument transformers.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-3.
PRC-017-0
R1.1.3. Communications systems,
where appropriate.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-2.
21
Mapping for requirements in PRC-017-0 are adapted from the mapping document developed by the Project 2007-17 Protection System Maintenance & Testing
drafting team.
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Appendix C – Mapping of Requirements from Existing Standards
Table 2: Mapping of SPS-Related Requirements in Existing NERC Reliability Standards
Existing
Standard
PRC-017-0
Requirement
R1.1.4. Batteries.
Proposal
Comments
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, Table 1-4.
PRC-017-0
R1.2. Documentation of maintenance and
testing intervals and their basis.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1 and R2.
PRC-017-0
R1.3. Summary of testing procedure.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1, Tables 1-1 – 1-5, and Table 2.
PRC-017-0
R1.4. Schedule for system testing.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1 and R2.
PRC-017-0
R1.5. Schedule for system maintenance.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R1 and R2
PRC-017-0
R1.6. Date last tested/maintained.
Addressed by Project 2007-17, Protection System
Maintenance and Testing
See PRC-005-2, R3 and associated Measures, R4
and associated Measure, and Data Retention.
Addressed by Project 2007-17, Protection System
Maintenance and Testing; this requirement is not
carried forward to the revised standard.
Existing reporting requirements that have no
discernible impact on promoting the reliable
operation of the bulk electric system are being
removed from NERC Reliability Standards in
Project 2013-02 Paragraph 81. The ERO Rules of
Procedures, Section 401: 3. Data Access, provide
the ability for NERC to obtain this information.
PRC-017-0
R2. The Transmission Owner, Generator Owner,
and Distribution Provider that owns an SPS
shall provide documentation of the program
and its implementation to the appropriate
Regional Reliability Organizations and NERC
on request (within 30 calendar days).
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Appendix D – Standards Committee Request for Research;
January 9, 2011
Request for Research
Project 2010-05.2
Phase 2 of Protection Systems: SPS and RAS
Introduction
NERC’s Standards Committee has tentatively identified this project for initiation in late 2012. Prior to then, there is a need
for additional research and scoping of the project to determine:
• What is the problem that this project will try to solve?
• Is the development of a standard the appropriate manner to solve that problem, or should alternative approaches
be used?
• If a standard is appropriate, what is the recommended solution to the problem?
Results based standards projects use the approach of defining the needs, goals, and objectives for the project. For this
project, we would like your assistance in this effort. Below is a draft problem statement for your consideration.
Need (Problem )
Special Protection Systems (SPS) and Remedial Action Schemes (RAS) can misoperate and negatively impact the
reliability of the BES.
Does the need above correctly document the concern described in the attached draft SAR?
Do you agree that this is a problem that needs to be addressed?
Is a standard the appropriate vehicle to address this problem, or should an alternative approach be used? If an alternative,
is recommended, what would that alternative be?
If development of a standard is appropriate, then please consider the following Goal
Goal (Solution)
Require the analysis, reporting, and correction of Misoperations of SPS and RAS.
Request
Please provide the Standards Committee with the following information:
•
•
•
•
An updated Need/Problem (or a statement of concurrence with the draft presented here)
A statement indicating whether or not you believe this problem is one which needs to be addressed
If you agree the problem needs to be addressed, a suggestion for how to address the problem
If you suggest a standard be developed to address the problem, then please provide
o An updated goal (or a statement of concurrence with the draft presented here)
o A set of objectives in support of that goal
o If you have any suggested changes to the attached draft SAR, please propose them
o If you have specific recommendations for requirements language or additional information, please include
them
Thank you in advance for your assistance.
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Appendix E – Scope of Work Approved by the Planning
Committee; June 8, 2011
As s e s s m e n t o f Sp e cia l P r o t e ct io n Sys t e m St a n d a r d s a n d Re g io n a l
P r a ct ice s
Proposal:
The SPCS proposes to conduct an assessment of the SPS-related PRC standards and definition of SPS, conduct an
assessment of existing regional practices summarizing commonality and differences, and to document its findings in a
report to the Planning Committee that can serve as a reference document for a standard drafting team that ultimately will
be assigned to review these standards. If deemed appropriate, the report could be used to support a Compliance
Application Notice (CAN) to address part of this issue until a revised definition and standard(s) are developed. The SPCS
further proposes this activity should be a joint effort with the Transmission Issues Subcommittee (TIS).
Rationale:
•
The SPCS scope calls for providing subject matter expertise for NERC Standards related to protection systems and
controls, and the SPCS work plan includes an assignment to review all existing PRC-series Reliability Standards, to
advise the Planning Committee of its assessment, and to develop Standards Authorization Requests, as appropriate, to
address any perceived deficiencies.
•
The SPCS has reviewed all PRC standards except the group of SPS standards. The SPCS had started assessment of these
standards, but the assessment was deferred due to other priority work such as the Power Plant and Transmission
System Protection Coordination technical reference document.
•
The SPCS has reviewed its work plan and determined that this is the next logical project for the SPCS. Work on the
Transmission System Phase Backup Protection reliability guideline is wrapping up at this time and the SPCS can make
the SPS review one of two priority activities for this year (the other is the document addressing operation of protection
systems in response to power swings).
•
The SPCS believes that a thorough review of SPS-related PRC standards would benefit from the expertise of TIS and the
SPCS recommends a joint SPCS/TIS effort coordinated by the SPCS. This proposal has been reviewed with and is
supported by TIS.
•
The SPCS proposes to conduct an assessment of the standards and definition of SPS, and conduct an assessment of
existing regional practices summarizing commonality and differences among the various regional practices.
•
The SPCS believes that differences among regional practices must be resolved through a formal process; a consensus
opinion of what constitutes an SPCS would lack standing unless it is vetted through a stakeholder process. The SPCS
proposes to document its findings in a report that can serve as a reference document for a standard drafting team that
ultimately will be assigned to review these standards. If deemed appropriate, the report could be used to support a
CAN to address part of this issue until a revised standard(s) is developed.
•
The scope of work for such a review is significant and direction should come through the NERC Planning Committee as
the body to which SPCS and TIS report.
•
The SPCS believes that an appropriate time frame for completing this report would be to submit a draft to the Planning
Committee at its March 2012 meeting. The SPCS and TIS believe this schedule is appropriate to support a thorough
review.
Approved by the NERC Planning Committee
June 8, 2011
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
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Appendix F – System Analysis and Modeling Subcommittee
Roster
John Simonelli
Chair
Director - Operations Support Services
ISO New England
Jonathan E Hayes
RE – SPP
Reliability Standards Development Engineer
Southwest Power Pool, Inc.
K. R Chakravarthi
Vice Chair
Manager, Interconnection and Special Studies
Southern Company Services, Inc.
Kenneth A. Donohoo
RE – TRE
Director System Planning
Oncor Electric Delivery
G Brantley Tillis, P.E.
RE – FRCC
Manager, Transmission Planning Florida
Progress Energy Florida
Hari Singh
RE – WECC
Transmission Asset Management
Xcel Energy, Inc.
Kiko Barredo
RE – FRCC – Alternate
Manager, Bulk Transmission Planning
Florida Power & Light Co.
Kent Bolton
RE – WECC – Alternate
Staff Engineer
Western Electricity Coordinating Council
Thomas C. Mielnik
RE – MRO
Manager Electric System Planning
MidAmerican Energy Co.
Digaunto Chatterjee
ISO/RTO
Manager of Transmission Expansion Planning
Midwest ISO, Inc.
Salva R. Andiappan
RE – MRO – Alternate
Manager - Modeling and Reliability Assessments
Midwest Reliability Organization
Patricia E Metro
Cooperative
Manager, Transmission and Reliability Standards
National Rural Electric Cooperative Association
Donal Kidney
RE – NPCC
Manager, System Compliance Program Implementation
Northeast Power Coordinating Council
Eric Mortenson, P.E.
Investor-Owned Utility
Principal Rates & Regulatory Specialist
Exelon Business Services Company
Bill Harm
RE – RFC
Senior Consultant
PJM Interconnection, L.L.C.
Amos Ang, P.E.
Investor-Owned Utility
Engineer, Transmission Interconnection Planning
Southern California Edison
Mark Byrd
RE – SERC
Manager - Transmission Planning
Progress Energy Carolinas
Bob Cummings
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Gary T Brownfield
RE – SERC – Alternate
Supervising Engineer, Transmission Planning
Ameren Services
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
45 of 48
Appendix G – System Protection and Control Subcommittee
Roster
William J. Miller
Chair
Principal Engineer
Exelon Corporation
Samuel Francis
RE – TRE
System Protection Specialist
Oncor Electric Delivery
Philip B. Winston
Vice Chair
Chief Engineer, Protection and Control
Southern Company
David Penney, P.E.
RE – TRE – Alternate
Senior Reliability Engineer
Texas Reliability Entity
Michael Putt
RE – FRCC
Manager, Protection and Control Engineering Applications
Florida Power & Light Co.
Baj Agrawal
RE – WECC
Principal Engineer
Arizona Public Service Company
Mark Gutzmann
RE – MRO
Manager, System Protection Engineering
Xcel Energy, Inc.
Miroslav Kostic
Canada Provincial
P&C Planning Manager, Transmission
Hydro One Networks, Inc.
Richard Quest
RE – MRO – Alternate
Principal Systems Protection Engineer
Midwest Reliability Organization
Sungsoo Kim
Canada Provincial
Section Manager – Protections and Technical Compliance
Ontario Power Generation Inc.
George Wegh
RE – NPCC
Manager
Northeast Utilities
Michael J. McDonald
Investor-Owned Utility
Principal Engineer, System Protection
Ameren Services Company
Quoc Le
RE – NPCC -- Alternate
Manager, System Planning and Protection
NPCC
Jonathan Sykes
Investor-Owned Utility
Manager of System Protection
Pacific Gas and Electric Company
Jeff Iler
RE – RFC
Principal Engineer, Protection and Control Engineering
American Electric Power
Charles W. Rogers
Transmission Dependent Utility
Principal Engineer
Consumers Energy Co.
Therron Wingard
RE – SERC
Principal Engineer
Southern Company
Joe T. Uchiyama
U.S. Federal
Senior Electrical Engineer
U.S. Bureau of Reclamation
David Greene
RE – SERC -- Alternate
Reliability Engineer
SERC Reliability Corporation
Daniel McNeely
U.S. Federal – Alternate
Engineer - System Protection and Analysis
Tennessee Valley Authority
Lynn Schroeder
RE – SPP
Manager, Substation Protection and Control
Westar Energy
Philip J. Tatro
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
46 of 48
Appendix H – Additional Contributors
Forrest Brock
Transmission Compliance Specialist
Western Farmers Electric Cooperative
Robert Creighton
Sr. Engineering Specialist, Transmission Planning
Nova Scotia Power, Inc.
Tom Gentile
Senior Director, Transmission Northeast
Quanta Technology
Bryan Gwyn
Senior Director, Protection and Control Asset Management
Quanta Technology
Gene Henneberg
Staff Protection Engineer
NV Energy
Greg Henry (formerly NERC Staff Coordinator for SAMS)
Lead Engineer, Smart Integrated Infrastructure
Black & Veatch
Bobby Jones
Planning Manager – Stability
Southern Company Services
John O’Connor
Principal Engineer
Progress Energy Carolinas
Slobodan Pajic
Senior Engineer, Energy Consulting
GE Energy Management
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
47 of 48
Appendix I – Revision History
Revision History
Version
Date
Modification(s)
0
March 5, 2013
Initial Document
0.1
April 18, 2013
Appendix A – Correction to remove trade names and replace with generic language
in the section, General Considerations for Simulation
NERC | Special Protection Systems (SPS) and Remedial Action Schemes (RAS) | April 2013
48 of 48
Standard PRC-012-1 — Remedial Action Scheme Review Procedure
A. Introduction
1.
Title:
Remedial Action Scheme Review Procedure
2.
Number:
PRC-012-1
3.
Purpose:
To ensure that all Remedial Action Schemes (RAS) are properly designed, meet
performance requirements, and are coordinated with other protection systems. To ensure that
maintenance and testing programs are developed and misoperations are analyzed and corrected.
4.
Applicability:
4.1. Regional Reliability Organization
5.
Effective Date: See Implementation Plan for the Revised Definition of “Remedial Action
Scheme”
B. Requirements
R1.
R2.
Each Regional Reliability Organization with a Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use a RAS shall have a documented Regional
Reliability Organization RAS review procedure to ensure that RAS comply with Regional
criteria and NERC Reliability Standards. The Regional RAS review procedure shall include:
R1.1.
Description of the process for submitting a proposed RAS for Regional Reliability
Organization review.
R1.2.
Requirements to provide data that describes design, operation, and modeling of a
RAS.
R1.3.
Requirements to demonstrate that the RAS shall be designed so that a single RAS
component failure, when the RAS was intended to operate, does not prevent the
interconnected transmission system from meeting the performance requirements
defined in Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0.
R1.4.
Requirements to demonstrate that the inadvertent operation of a RAS shall meet the
same performance requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was designed, and not exceed TPL-003-0.
R1.5.
Requirements to demonstrate the proposed RAS will coordinate with other protection
and control systems and applicable Regional Reliability Organization Emergency
procedures.
R1.6.
Regional Reliability Organization definition of misoperation.
R1.7.
Requirements for analysis and documentation of corrective action plans for all RAS
misoperations.
R1.8.
Identification of the Regional Reliability Organization group responsible for the
Regional Reliability Organization’s review procedure and the process for Regional
Reliability Organization approval of the procedure.
R1.9.
Determination, as appropriate, of maintenance and testing requirements.
The Regional Reliability Organization shall provide affected Regional Reliability
Organizations and NERC with documentation of its RAS review procedure on request (within
30 calendar days).
1 of 2
Standard PRC-012-1 — Remedial Action Scheme Review Procedure
C. Measures
M1. The Regional Reliability Organization with a Transmission Owner, Generator Owner, or
Distribution Provider using or planning to use a RAS shall have a documented Regional review
procedure as defined in Reliability Standard PRC-012-1_R1.
M2. The Regional Reliability Organization shall have evidence it provided affected Regional
Reliability Organizations and NERC with documentation of its RAS review procedure on
request (within 30 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: NERC.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Documentation of the Regional Reliability Organization’s procedure is
missing one of the items listed in Reliability Standard PRC-012-1_R1.
2.2. Level 2:
Documentation of the Regional Reliability Organization’s procedure is
missing two of the items listed in Reliability Standard PRC-012-1_R1.
2.3. Level 3:
Documentation of the Regional Reliability Organization’s procedure is
missing three of the items listed in Reliability Standard PRC-012-1_R1.
2.4. Level 4:
Documentation of the Regional Reliability Organization’s procedure was
not provided or is missing four or more of the items listed in Reliability Standard PRC012-1_R1.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
November 13,
2014
Adopted by the NERC Board of Trustees
Replaced references to
Special Protection
System and SPS with
Remedial Action Scheme
and RAS
2 of 2
* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-012-1 — Remedial Action Scheme Review Procedure
United States
Standard
Requirement
PRC-012-1
All
Enforcement Date
Inactive Date
This standard has not yet been approved by the applicable regulatory authority.
Printed On: May 20, 2016, 11:48 AM
Standard PRC-013-1 — Remedial Action Scheme Database
A. Introduction
1.
Title:
Remedial Action Scheme Database
2.
Number:
PRC-013-1
3.
Purpose:
To ensure that all Remedial Action Schemes (RAS) are properly designed, meet
performance requirements, and are coordinated with other protection systems.
4.
Applicability:
4.1. Regional Reliability Organization
5.
Effective Date: See Implementation Plan for the Revised Definition of “Remedial Action
Scheme”
B. Requirements
R1.
R2.
The Regional Reliability Organization that has a Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall maintain a RAS database. The database shall
include the following types of information:
R1.1.
Design Objectives — Contingencies and system conditions for which the RAS was
designed,
R1.2.
Operation — The actions taken by the RAS in response to Disturbance conditions,
and
R1.3.
Modeling — Information on detection logic or relay settings that control operation of
the RAS.
The Regional Reliability Organization shall provide to affected Regional Reliability
Organization(s) and NERC documentation of its database or the information therein on request
(within 30 calendar days).
C. Measures
M1. The Regional Reliability Organization that has a Transmission Owner, Generator Owner, or
Distribution Providers with a RAS installed, shall have a RAS database as defined in PRC-0131_R1 of this Reliability Standard.
M2. The Regional Reliability Organization shall have evidence it provided documentation of its
database or the information therein, to affected Regional Reliability Organization(s) and NERC
on request (within 30 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: NERC.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
1 of 2
Standard PRC-013-1 — Remedial Action Scheme Database
2.
Levels of Non-Compliance
2.1. Level 1:
The Regional Reliability Organization’s database is missing one of the items
listed in Reliability Standard PRC-013-1_R1.
2.2. Level 2:
The Regional Reliability Organization’s database is missing two of the
items listed in Reliability Standard PRC-013-1_R1.
2.3. Level 3:
Not applicable.
2.4. Level 4:
The Regional Reliability Organization’s database was not provided or is
missing all of the elements listed in Reliability Standard PRC-013-1_R1.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Dave
New
1
November 13,
2014
Adopted by the NERC Board of Trustees
Replaced references to
Special Protection
System and SPS with
Remedial Action Scheme
and RAS
2 of 2
* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-013-1 — Remedial Action Scheme Database
United States
Standard
Requirement
PRC-013-1
All
Enforcement Date
Inactive Date
This standard has not yet been approved by the applicable regulatory authority.
Printed On: May 20, 2016, 11:49 AM
Standard PRC-014-1 — Remedial Action Scheme Assessment
A. Introduction
1.
Title:
Remedial Action Scheme Assessment
2.
Number:
PRC-014-1
3.
Purpose:
To ensure that all Remedial Action Schemes (RAS) are properly designed, meet
performance requirements, and are coordinated with other protection systems. To ensure that
maintenance and testing programs are developed and misoperations are analyzed and corrected.
4.
Applicability:
4.1. Regional Reliability Organization
5.
Effective Date: See Implementation Plan for the Revised Definition of “Remedial Action
Scheme”
B. Requirements
R1.
The Regional Reliability Organization shall assess the operation, coordination, and
effectiveness of all RAS installed in its Region at least once every five years for compliance
with NERC Reliability Standards and Regional criteria.
R2.
The Regional Reliability Organization shall provide either a summary report or a detailed
report of its assessment of the operation, coordination, and effectiveness of all RAS installed in
its Region to affected Regional Reliability Organizations or NERC on request (within 30
calendar days).
R3.
The documentation of the Regional Reliability Organization’s RAS assessment shall include
the following elements:
R3.1.
Identification of group conducting the assessment and the date the assessment was
performed.
R3.2.
Study years, system conditions, and contingencies analyzed in the technical studies on
which the assessment is based and when those technical studies were performed.
R3.3.
Identification of RAS that were found not to comply with NERC standards and
Regional Reliability Organization criteria.
R3.4.
Discussion of any coordination problems found between a RAS and other protection
and control systems.
R3.5.
Provide corrective action plans for non-compliant RAS.
C. Measures
M1. The Regional Reliability Organization shall assess the operation, coordination, and
effectiveness of all RAS installed in its Region at least once every five years for compliance
with NERC standards and Regional criteria.
M2. The Regional Reliability Organization shall provide either a summary report or a detailed
report of this assessment to affected Regional Reliability Organizations or NERC on request
(within 30 calendar days).
M3. The Regional Reliability Organization’s documentation of the RAS assessment shall include
all elements as defined in Reliability Standard PRC-014-1_R3.
1 of 2
Standard PRC-014-1 — Remedial Action Scheme Assessment
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: NERC.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
The summary (or detailed) Regional RAS assessment is missing one of the
items listed in Reliability Standard PRC-014-1_R3.
2.2. Level 2:
The summary (or detailed) Regional RAS assessment is missing two of the
items listed in Reliability Standard PRC-014-1_3.
2.3. Level 3:
The summary (or detailed) Regional RAS assessment is missing three of the
items listed in Reliability Standard PRC-014-1_R3.
2.4. Level 4:
The summary (or detailed) Regional RAS assessment is missing more than
three of the items listed in Reliability Standard PRC-014-1_R3 or was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
November 13,
2014
Adopted by the NERC Board of Trustees
Replaced references to
Special Protection System
and SPS with Remedial
Action Scheme and RAS
2 of 2
* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-014-1 — Remedial Action Scheme Assessment
United States
Standard
Requirement
PRC-014-1
All
Enforcement Date
Inactive Date
This standard has not yet been approved by the applicable regulatory authority.
Printed On: May 20, 2016, 11:50 AM
Standard PRC-015-1 — Remedial Action Scheme Data and Documentation
A. Introduction
1.
Title:
Remedial Action Scheme Data and Documentation
2.
Number:
PRC-015-1
3.
Purpose:
To ensure that all Remedial Action Schemes (RAS) are properly designed, meet
performance requirements, and are coordinated with other protection systems. To ensure that
maintenance and testing programs are developed and misoperations are analyzed and corrected.
4.
Applicability:
4.1. Transmission Owner that owns a RAS
4.2. Generator Owner that owns a RAS
4.3. Distribution Provider that owns a RAS
5.
Effective Date: See Implementation Plan for the Revised Definition of “Remedial Action
Scheme”
B. Requirements
R1.
The Transmission Owner, Generator Owner, and Distribution Provider that owns a RAS shall
maintain a list of and provide data for existing and proposed RAS as specified in Reliability
Standard PRC-013-1 R1.
R2.
The Transmission Owner, Generator Owner, and Distribution Provider that owns a RAS shall
have evidence it reviewed new or functionally modified RAS in accordance with the Regional
Reliability Organization’s procedures as defined in Reliability Standard PRC-012-1_R1 prior
to being placed in service.
R3.
The Transmission Owner, Generator Owner, and Distribution Provider that owns a RAS shall
provide documentation of RAS data and the results of Studies that show compliance of new or
functionally modified RAS with NERC Reliability Standards and Regional Reliability
Organization criteria to affected Regional Reliability Organizations and NERC on request
(within 30 calendar days).
C. Measures
M1. The Transmission Owner, Generator Owner, and Distribution Provider that owns a RAS shall
have evidence it maintains a list of and provides data for existing and proposed RAS as defined
in Reliability Standard PRC-013-1_R1.
M2. The Transmission Owner, Generator Owner, and Distribution Provider that owns a RAS shall
have evidence it reviewed new or functionally modified RAS in accordance with the Regional
Reliability Organization’s procedures as defined in Reliability Standard PRC-012-1_R1 prior
to being placed in service.
M3. The Transmission Owner, Generator Owner, and Distribution Provider that owns a RAS shall
have evidence it provided documentation of RAS data and the results of studies that show
compliance of new or functionally modified RAS with NERC standards and Regional
Reliability Organization criteria to affected Regional Reliability Organizations and NERC on
request (within 30 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
1 of 2
Standard PRC-015-1 — Remedial Action Scheme Data and Documentation
Compliance Monitor: Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days).
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
RAS owners provided RAS data, but was incomplete according to the
Regional Reliability Organization RAS database requirements.
2.2. Level 2:
RAS owners provided results of studies that show compliance of new or
functionally modified RAS with the NERC Planning Standards and Regional Reliability
Organization criteria, but were incomplete according to the Regional Reliability
Organization procedures for Reliability Standard PRC-012-1_R1.
2.3. Level 3:
Not applicable.
2.4. Level 4:
No RAS data was provided in accordance with Regional Reliability
Organization RAS database requirements for Standard PRC-012-1_R1, or the results of
studies that show compliance of new or functionally modified RAS with the NERC
Reliability Standards and Regional Reliability Organization criteria were not provided in
accordance with Regional Reliability Organization procedures for Reliability Standard
PRC-012-1_R1.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
November 13,
2014
Adopted by the NERC Board of Trustees
Replaced references to
Special Protection
System and SPS with
Remedial Action Scheme
and RAS
1
November 19,
2015
FERC Order issued approving PRC-015-1.
Docket No. RM15-13-000.
2 of 2
* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-015-1 — Remedial Action Scheme Data and Documentation
United States
Standard
Requirement
Enforcement Date
PRC-015-1
All
04/01/2017
Inactive Date
Printed On: May 20, 2016, 11:51 AM
Standard PRC-016-1 — Remedial Action Scheme Misoperations
A. Introduction
1.
Title: Remedial Action Scheme Misoperations
2.
Number:
3.
Purpose: To ensure that all Remedial Action Schemes (RAS) are properly designed,
meet performance requirements, and are coordinated with other protection systems. To
ensure that maintenance and testing programs are developed and misoperations are
analyzed and corrected.
4.
Applicability:
PRC-016-1
4.1. Transmission Owner that owns a RAS.
4.2. Generator Owner that owns a RAS.
4.3. Distribution Provider that owns a RAS.
5.
Effective Date: See Implementation Plan for the Revised Definition of “Remedial
Action Scheme”
B. Requirements
R1. The Transmission Owner, Generator Owner, and Distribution Provider that owns a
RAS shall analyze its RAS operations and maintain a record of all misoperations in
accordance with the Regional RAS review procedure specified in Reliability Standard
PRC-012-1_R1.
R2. The Transmission Owner, Generator Owner, and Distribution Provider that owns a
RAS shall take corrective actions to avoid future misoperations.
R3. The Transmission Owner, Generator Owner, and Distribution Provider that owns a
RAS shall provide documentation of the misoperation analyses and the corrective
action plans to its Regional Reliability Organization and NERC on request (within 90
calendar days).
C. Measures
M1. The Transmission Owner, Generator Owner, and Distribution Provider that owns a
RAS shall have evidence it analyzed RAS operations and maintained a record of all
misoperations in accordance with the Regional RAS review procedure specified in
Reliability Standard PRC-012-1_R1.
M2. The Transmission Owner, Generator Owner, and Distribution Provider that owns a
RAS shall have evidence it took corrective actions to avoid future misoperations.
M3. The Transmission Owner, Generator Owner, and Distribution Provider that owns a
RAS shall have evidence it provided documentation of the misoperation analyses and
the corrective action plans to the affected Regional Reliability Organization and NERC
on request (within 90 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Page 1 of 3
Standard PRC-016-1 — Remedial Action Scheme Misoperations
Compliance Monitor: Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
On request [within 90 calendar days of the incident or on request (within 30
calendar days) if requested more than 90 calendar days after the incident.]
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Documentation of RAS misoperations is complete but
documentation of corrective actions taken for all identified RAS misoperations is
incomplete.
2.2. Level 2:
Documentation of corrective actions taken for RAS misoperations
is complete but documentation of RAS misoperations is incomplete.
2.3. Level 3:
incomplete.
Documentation of RAS misoperations and corrective actions is
2.4. Level 4:
No documentation of RAS misoperations or corrective actions.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
February 8,
2005
Adopted by NERC Board of Trustees
New
0
July 3, 2007
Change reference in Measure 1 from
“PRC-016-0_R1” to “PRC-012-1_R1.”
Errata
0.1
October 29,
2008
BOT adopted errata changes; updated
version number to “0.1”
Errata
0.1
May 13, 2009
FERC Approved – Updated Effective
Date
Revised
1
November 13,
2014
Adopted by the NERC Board of
Trustees
Replaced references to
Special Protection
System and SPS with
Remedial Action
Scheme and RAS
Page 2 of 3
Standard PRC-016-1 — Remedial Action Scheme Misoperations
1
November 19,
2015
FERC Order issued approving PRC-016-1.
Docket No. RM15-13-000.
Page 3 of 3
* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-016-1 — Remedial Action Scheme Misoperations
United States
Standard
Requirement
Enforcement Date
PRC-016-1
All
04/01/2017
Inactive Date
Printed On: May 20, 2016, 11:51 AM
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Informal Comment Period Open through May 20, 2015
Now Available
A 21-day informal comment period for PRC-012-2 – Remedial Action Schemes is open through 8 p.m.
Eastern, Wednesday, May 20, 2015.
For this informal posting, the drafting team is soliciting stakeholder feedback on the scope and work
product developed thus far. The drafting team will use the informal feedback to finalize the preliminary
draft of PRC-012-2. Stakeholders may communicate additional feedback directly to the drafting team
through its open meetings leading up to the first formal posting. The next meeting is scheduled for June
8-11, 2015. Meeting details will be posted to the NERC calendar early May 2015.
Background
This project is addressing all aspects of Remedial Action Schemes (RAS) and Special Protection Systems
(SPS) contained in the RAS/SPS-related Reliability Standards: PRC-012-1, PRC-013-1, PRC-014-1, PRC-0151, and PRC-016-1. The maintenance of the Protection System components associated with RAS (PRC-0171 Remedial Action Scheme Maintenance and Testing) are already addressed in PRC-005-2. PRC-012-2
addresses the testing of the non-Protection System components associated with RAS/SPS.
In FERC Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and
PRC-014-0 as “fill-in-the-blank” standards and did not approve or remand them because they are
applicable to the Regional Reliability Organizations (RROs), assigning the RROs the responsibility to
establish regional procedures and databases, and to assess and document the operation, coordination,
and compliance of RAS/SPS. The deference to regional practices precludes the consistent application of
RAS/SPS-related Reliability Standard requirements.
The proposed draft of PRC-012-2 corrects the applicability of the fill-in-the-blank standards by assigning
the requirement responsibilities to the specific users, owners, and operators of the Bulk-Power System;
and incorporates the reliability objectives of all the RAS/SPS-related standards.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted
on the project page.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2010-05.3
Phase 3 of Protection Systems: RAS | April 30, 2015
2
Survey Report
Survey Details
Name
2010-05.3 Phase 3 of Protections Systems: RAS | PRC-012-2
Description
4/30/2015
Start Date
End Date
5/20/2015
Associated Ballots
Survey Questions
1.
RAS review and approval (Requirements R1, R2 and R3): Do you agree that RAS should be
reviewed and approved by an independent party prior to placing the RAS in-service? If no, please state
the basis for your disagreement and an alternative approach.
Yes
No
2.
Information listed in Attachment 1 (Requirement R1): Do you agree that the RAS information
required in Attachment 1 is a comprehensive list? If no, please identify what other information you
think is necessary for a thorough RAS review.
Yes
No
3.
Choice of Reliability Coordinator (Requirements R1, R2 and R3): Do you agree with the Reliability
Coordinator being the functional entity designated to review the RAS? If no, please provide the basis
for your disagreement, your choice of functional entity to conduct the reviews, and the rationale for
your choice.
Yes
No
4.
Checklist in Attachment 2 (Requirement R2): Do you agree that the checklist in Attachment 2
provides a comprehensive guide for the Reliability Coordinator to facilitate a thorough RAS review? If
no, please identify what other reliability-related considerations should be included in Attachment 2 and
the rationale for your choice.
Yes
No
5.
Choice of Transmission Planner (Requirement R4): The Transmission Planner is required to
perform a technical evaluation (planning analyses) of each RAS at least once every 60 full calendar
months to verify the continued effectiveness and coordination of the RAS, as well as the BES
performance following an inadvertent operation of the RAS. Do you agree with the Transmission
Planner being the functional entity designated to evaluate the RAS? If no, please provide the basis for
your disagreement, your choice of functional entity to conduct the evaluations, and the rationale for
your choice.
Yes
No
6.
No RAS Classification (Requirement R4): The drafting team considered the RAS classification
systems used by several Regions to be rooted in PRC-012, Requirement R1, R1.4. which reads:
“Requirements to demonstrate that the inadvertent operation of a RAS shall meet the same
performance requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the contingency for
which it was designed, and not exceed TPL-003-0.” Although, the drafting team is not proposing to use
formal RAS classifications, the intent of PRC-012, Requirement R1, R1.4. is retained in Requirement 4
and Attachment 1. Do you agree that the language of Requirement R4, its Parts, and Attachment 1
accomplish the objectives of RAS “classification” without having a formal RAS classification system in
the standard? If no, please provide the basis for your disagreement and describe an alternate proposal.
Yes
No
7.
RAS Operational Analyses (Requirement R6): Requirement R6 mandates each RAS-owner analyze
each RAS operation or failure of a RAS to operate to identify performance deficiencies Do you agree
that the application of Requirement R6 and its Parts would identify performance deficiencies in RAS? If
no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
8.
Corrective Action Plans (Requirements R5, R7, and R8): Do you agree that the application of
Requirements R5, R7, and R8 would address the reliability objectives associated with CAPs? If no,
please provide the basis for your disagreement and describe an alternate proposal.
Yes
No
9.
Functional Testing of RAS (Requirement R9): Do you agree that functional testing of each RAS
would verify the overall RAS performance and the proper operation of non-Protection System
components? If no, please provide the basis for your disagreement and describe an alternate proposal.
Yes
No
10.
Choice of Reliability Coordinator (Requirement R10): Do you agree with the Reliability
Coordinator being the functional entity designated to maintain the RAS database? If no, please provide
the basis for your disagreement, your choice of functional entity, and the rationale for your choice.
Yes
No
11.
Information listed in Attachment 3 (Requirement R10): Do you agree that the RAS information
required in Attachment 3 provides the Reliability Coordinator with enough detail of each RAS to meet
its reliability-related needs? If no, please identify what other reliability-related information should be
included in Attachment 3 and the rationale for your choice.
Yes
No
12.
Requirement R11: Is there a reliability benefit of Requirement R11? Please provide the rationale
for your answer.
Yes
No
13.
Choice of RAS-entity (Requirement R11): Do you agree with the RAS-entity being the entity
designated to provide the detailed RAS information to other registered entities with a reliability-related
need? If no, please provide the basis for your disagreement, your choice of entity, and the rationale for
your choice.
Yes
No
14.
If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Responses By Question
1.
RAS review and approval (Requirements R1, R2 and R3): Do you agree that RAS should be reviewed
and approved by an independent party prior to placing the RAS in-service? If no, please state the basis for
your disagreement and an alternative approach.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Note that Attachment 1, section III Implementation, criterion 2 should be
revised slightly as it is too wide and somewhat ambiguous. The
devices to be analyzed should be tied to the protection system
definition and performance to meet TPL-001-4.
“Documentation showing that any multifunction devised used to perform
RAS functions…”
Revise the above to state something like, “Documentation showing that
a malfunction of a NERC Protection System component in the RAS
does not compromise the ability of the RAS to meet TPL-001-4 and its
successors.”
0
Likes:
0
Dislikes:
Thomas Foltz - AEP - 5 -
Document Name:
Answer Comment:
Selected Answer:
Yes
Answer Comment:
While we do not object to the RAS being reviewed and approved by an
independent party for new systems, AEP seeks clarity to ensure that
existing evaluations on record, performed by the RRO, would be
grandfathered.
Document Name:
0
Likes:
0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
Answer Comment:
We agree that a RAS should be reviewed prior to placing in service.
However it is not clear what an independent party is. If that party is the
RC (or in our proposal, under Q3 below, the RC or the PC depending
on the time frame), then that should be fine. Otherwise, please specify.
Document Name:
0
Likes:
0
Dislikes:
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Answer Comment:
Selected Answer:
No
Comments: PacifiCorp does not agree that the RAS should be reviewed
and approved by an independent party prior to placing the RAS in
service. PacifiCorp believes that RAS review should be undertaken by
the planning coordinator, the transmission planner and neighboring
transmission planners as they are the parties that possess the requisite
knowledge to make a determination as to the appropriateness of the
RAS.
0
Likes:
0
Dislikes:
Jared Shakespeare - Peak Reliability - 1 -
Document Name:
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Yes
Answer Comment:
We agree that RAS should be approved prior to service. The R1
approval process should add a period of time that the RAS entity should
submit the RAS information prior to the expected in-service date to
ensure adequate time for review is provided.
R1. At least 180 days prior to placing a new or functionally modified
RAS in‐service, or retiring an existing RAS, each RAS‐entity shall
submit the information identified in Attachment 1 and Attachment 3 to
the reviewing Reliability Coordinator(s). At least 30 days prior to
placing an RAS in service as part of a CAP, each RAS entity shall
submit updated Attachment 1 and Attachment 3
information. [Violation Risk Factor:] [Time Horizon:]
R2 should be modified as follows to include the Attachment 3
information.
R2. For each RAS submitted pursuant to Requirement R1, each
reviewing Reliability Coordinator shall, within four full calendar months
of receipt of Attachment 1 and Attachment 3 materials, or on a
mutually agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written feedback to the
RAS‐entity. [Violation Risk Factor:] [Time Horizon: ]
Document Name:
0
Likes:
0
Dislikes:
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Yes
We suggest that R1 may be adjusted to clarify that the intent is for the
data to be submitted to the RC to perform its analysis (per R2) prior to
putting the RAS in-service. The current wording is unclear in R1 that
the RAS may not be put into service until the approval is received by
the RC (per R3).
For example: “R1: Each RAS‐entity shall submit the information
identified in Attachment 1 to the
reviewing Reliability Coordinator(s) for approval prior to placing a new
or functionally modified RAS in‐service or retiring an existing RAS.”
0
Likes:
0
Dislikes:
Gul Khan - Oncor Electric Delivery - 2 - TRE
Document Name:
Answer Comment:
Selected Answer:
Yes
Oncor Electric Delivery believes that it is a good idea to have an
independent party review any RAS. However, 90 days for the review
seems more reasonable since they are just reviewing the scheme.
Document Name:
0
Likes:
0
Dislikes:
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
However, Duke Energy feels that an Independent Third Party is
necessary only in the rare occasions when a “conflict of interest”
exists among the RAS Entity, PC, TP, or other entity that could be
involved in the planning or implementation of a RAS.
Likes:
0
Dislikes:
Document Name:
Answer Comment:
0
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Yes, RAS should be reviewed and approved by the Reliability
Coordinator prior to being placed in-service instead of the independent
party.
Document Name:
0
Likes:
0
Dislikes:
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
But we do not believe this should be the RC. The current NERC
Regions (not Regional Entities) have long-standing and effective
committee structures that give SPSs thorough technical reviews
involving engineering staff from all impacted entities. We would
recommend the drafting team allow the use of collaborative forums (in
which RCs and PC participate) as a means to perform the analysis and
reviews in the standard.
Document Name:
0
Likes:
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
An independent party review for an RAS application is inappropriate
since an independent party may not understand the complexity of the
application without significant investment in time, resources and
experience. In addition, an independent party may not understand the
required coordination across interconnected systems and may not be
as invested in a positive and effective outcome as a potentially
impacted party. An alternative approach would be to use a coordinated
review by potentially impacted parties including Planning Authorities or
Regional Entities.
Document Name:
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The Transmission Planner or Planning Coordinator, where RAS
impacts multiple Transmission Planners, is the correct function to
determine where a RAS Scheme is required. The SDT has not
justified why a review step is needed. No other Facility upgrade,
installation or protection system addition requires a third party
review. There is a planned Protection System Coordination Standard
but that is very limited in its coordination. The need for an RAS is
determined from TPL studies and planned system performance. The
standard can provide the RC with an opportunity to provide opinion, but
not approval. There is no need for a third party review.
Document Name:
0
Likes:
0
Dislikes:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
However, Tri-State believes there should be additional language added
to acknowledge that Transmission Operators should be allowed to
provisionally implement a proposed RAS in cases where there are
immediate reliability needs. The standard as currently drafted does not
allow for this.
Document Name:
0
Likes:
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
We agree with the need to have a higher level reliability authority with a
Wide Area view such as Planning Coordinator or Reliability
Coordinator. However, we do not understand the emphasis on
independence especially when there are FERC standards of conduct
and entity level codes of conduct. Furthermore, selecting a Reliability
Coordinator or Planning Coordinator will not guarantee this
independence anyway as there are still Reliability Coordinators and
Planning Coordinators affiliated with equipment owners. Thus, we
suggest focusing on the functional entity that should be responsible
which we believe is the Planning Coordinator. When entities were
registered any issues with independence should have been resolved.
Document Name:
0
Likes:
0
Dislikes:
Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Answer Comment:
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
1)
Hydro One Networks Inc. agrees with NPCC in that:
Because of its familiarity with its system, it is appropriate for the
RC to review a RAS, and requirement R1 identifies the RC as the
reviewer. We note that the RC may not be an “independent
party” nor does the requirement calls for an “independent
party.” Conducting a proper review of the RAS’s performance
and design is more critical than maintaining “independence”. An
alternative approach is used within NPCC. The PC has the
accountability to seek approval for deployment of a new or
modified RAS and this process is outlined in NPCC Directory 7,
Appendix B. The review is conducted by a group of entities
including subject matter experts from RC, TOs, PCs.
Document Name:
Likes:
1
Dislikes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
As specified by the SDT, RAS are complex schemes with lots of
possible actions that can have a significant impact on BES reliability. It
is essential for those schemes to be reviewed by independent entities
with expertise in various fields. However, Hydro-Quebec TransEnergie
(HQT) thinks that the RC may not always be an independent party as a
RAS reviewer. Some RCs have multiple PCs and TOPs within their
footprint. Some other RCs perform also TOP functions related to RAS
utilization on their BES system.
Document Name:
0
Likes:
0
Dislikes:
Answer Comment:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
Yes
Answer Comment:
Answer Comment:
Texas RE recommends providing some clarification around what it
means to be a RAS-entity and RAS-owner. The Functional Entity
referred to as “RAS-entity” should be the “RAS-owner” if there is only a
single owner, correct? Who does the designation for the
representation? Again, is that assumed to be the owner in a single
owner RAS?
Document Name:
0
Likes:
0
Dislikes:
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
1)
Hydro One Networks Inc. agrees with NPCC in that:
Because of its familiarity with its system, it is appropriate for the
RC to review a RAS, and requirement R1 identifies the RC as the
reviewer. We note that the RC may not be an “independent
party” nor does the requirement calls for an “independent
party.” Conducting a proper review of the RAS’s performance
and design is more critical than maintaining “independence”. An
alternative approach is used within NPCC. The PC has the
accountability to seek approval for deployment of a new or
modified RAS and this process is outlined in NPCC Directory 7,
Appendix B. The review is conducted by a group of entities
including subject matter experts from RC, TOs, PCs.
Document Name:
0
Likes:
0
Dislikes:
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The owner of any protection scheme should be responsible for the
correct design and implementation of the scheme – RAS or not. Just
like the design of switching to create a blackstart cranking path by a
TOP in EOP-005-2, Requirement 6 must be verified by that TOP, the
owner of the RAS should be held to the same expectation that the RAS
is correctly designed and implemented. If the SDT still believes that
some sort of review is required, then that review should be limited in
scope to reviewing the generic content of the RAS design and not delve
into the technical depth identified in some parts of Attachment 2.
Document Name:
0
Likes:
0
Dislikes:
Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Answer Comment:
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Answer Comment:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
No
Answer Comment:
For new or functionally modified RAS’s, the standard should be written
in a way that ensures the appropriate functional entities are involved in
the 1) identification of need for an RAS, 2) initial design and
assessment of the RAS, and 3) coordination with other functional
entities who may be impacted by operation of the RAS, before a new or
functionally modified RAS is placed in-service. There may be some
registry situations where all three of these objectives can be
accomplished within the same company if no neighboring entities are
impacted by the RAS. In such instances, review and approval by an
“independent party” should not be a pre-requisite to placing an RAS inservice. We have no objection to involving the appropriate Reliability
Coordinator(s) in these pre-requisite steps to RAS implementation.
Document Name:
0
Likes:
0
Dislikes:
2.
Information listed in Attachment 1 (Requirement R1): Do you agree that the RAS information required
in Attachment 1 is a comprehensive list? If no, please identify what other information you think is
necessary for a thorough RAS review.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Thomas Foltz - AEP - 5 -
Selected Answer:
No
Answer Comment:
More detail is needed regarding RAS retirement. The RAS Entity must
provide clarity regarding what system conditions would qualify the RAS
to be retired/disabled, in order to prevent an RAS from being in service
when one is not required.
Document Name:
0
Likes:
0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
No
We generally agree with the information required in Attachment 1, but
suggest the following changes:
Under Item II, second last bullet: revise “An evaluation indicating that
the RAS avoids adverse interactions with other RAS, and protection
and control systems.” to “An evaluation demonstration that the RAS
settings and operations are properly coordinated with those of other
RAS and protection and control systems”.
In addition, we propose that the SDT to add/specify the minimum
design criteria as they are needed to achieve both dependability and
security. Clear acceptable design criteria should to be included in the
standard to allow common RAS design practice across the continent. In
the absence of minimum design requirements, it will be difficult for the
RC to assess and for the RAS owners to design the appropriate level of
redundancy as one of the actions specified in the Attachment 1
requires. Further, it is not clear if “interconnected transmission system”
refers to Bulk Electric System as defined by NERC. Please clarify.
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
No
Documentation showing coordination with other NERC functional
entities that may be impacted by the RAS beyond RCs.
0
Likes:
0
Dislikes:
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Document Name:
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
No
Answer Comment:
Answer Comment:
The third item in Section II only requires a summary of technical studies
be provided. In addition to the summary, the technical studies
themselves should be provided.
Document Name:
0
Likes:
0
Dislikes:
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Oncor Electric Delivery believes the list contains more than is
necessary for a review and cannot always be obtained for every
RAS. In fact, unless the RAS is an existing system during the review
period there are usually no schematics to review so I do not believe it is
appropriate to request schematic diagrams. The second bullet under
General section I asks for “functionality of a new RAS”, which would be
a relay functional diagram that depicts how the scheme works and that
would be available during the review process.
Document Name:
Likes:
Answer Comment:
0
0
Dislikes:
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
ERCOT supports the SRC comments regarding Attachment 1.
Document Name:
0
Likes:
0
Dislikes:
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
No
Answer Comment:
Duke Energy requests further explanation on the removal of the
“extreme event” classification.
Document Name:
0
Likes:
0
Dislikes:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Answer Comment:
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
From the Attachment 1 introductory paragraph, “When a RAS has been
previously reviewed, only the proposed modifications to that RAS
require review; however, it will be helpful to the reviewers if the RAS
entity provides a summary of the previously approved functionality.” In
order to effectively review a proposed modification, a reviewer has to
understand the original RAS functionality. Suggest changing the
wording to “…however, the RAS entity must provide a summary of the
previously approved functionality.” Requirement R1 and Attachment 1
mandate “Functionality of new RAS or proposed functional modification
to existing RAS and documentation of the pre- and post-modified
functionality of the RAS” is under I. General, and in Requirement R1 as
information that has to be submitted. The wording in the introductory
paragraph needs to be revised.
In the RAS Retirement Section suggest revising the wording of the
second bullet to read:
A summary of applicable technical studies and technical justifications
needs to be provided upon which the decision to retire the RAS is
based.
The term “interconnected transmission system” in Section III, bullet 4, is
not clear. This is critical as it would affect the redundancy requirement,
especially to RAS installed only to mitigate local BES issues. “System”,
being defined in the NERC Glossary, should be capitalized.
Document Name:
0
Likes:
0
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
No
The 3rd and 4th boxes under "III. Implementation" contain undefined
terms, that are unclear, confusing, and duplicative. Tri-State
recommends replacing both boxes with:
“Documentation to demonstrate that any single piece of the equipment
used to implement the RAS can either be taken out of service or fail,
without disabling or compromising the reliability of the RAS.”
0
Likes:
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Document Name:
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
While we agree that Attachment 1 includes an exhaustive list of
information, we have three concerns with Attachment 1. First, it
includes a reference to performance in the TPL-001-4 studies. There is
no need to reference the TPL standard anywhere in this standard. TPL
should stand alone and will ensure that those performance
requirements are met. There have been issues in the past when
standards cross-reference other standards. Second, the information
required describing the equipment we believe is more detail than is
needed to be reviewed by the PC or RC. The PC and RC simply need
the information such as the potential actions and associated
contingencies and any failure modes (e.g. RAS partially operates)
which could include an expanded list of contingencies to study along
with RAS actions. They do not need to be familiar with the actual
equipment to perform this review. Third, we do not believe it should be
the RAS-entity (i.e. equipment owner) that submits the evaluation of
interactions with other RAS. Rather, we believe this is the PC’s
responsibility and the PC should already have studied and approved
the RAS at this juncture.
Document Name:
0
Likes:
0
Dislikes:
Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
David Jendras - Ameren - Ameren Services - 3 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
Requirement R1 currently requires the ‘RAS-entity’ to provide the
documentation in Attachment 1. The ‘RAS-entity’ term is a very
generic term as either the RAS-Owner or RAS-Planner could be
identified as a ‘RAS-entity’. The standard should be more
specific as to who should provide the information in Attachment
1. The RAS-Owner can only provide the information in Section I
and Section III in Attachment 1. Section II should be specific to
the Transmission Planner/RAS-Planner as the RAS-Owner
(Transmission Owner) does not have all the tools and information
to perform and provide the studies/documentation for this
section.
2) Attachment 1 is specific to identifying which documentation
should be provided by a RAS-entity. In the Implementation
(Section III) requirements, there is a requirement that states
documentation must be provided to show “that an appropriate
level of redundancy is provided…” If there is a requirement to
provide redundancy, it should be a separate requirement,
explicitly stated, and not reside in an Attachment outside of
Requirement R1, where this crucial detail could easily be missed.
3) The statement, “the RC may request additional information on
any reliability issue related to the RAS” should be moved from
Attachment 2 to Attachment 1.
4) The checklist particularly that in Attachment 1 should be
shortened and/or replaced by a simpler list. The reviewer (RC)
may further decide on the details.
5) Hydro One Networks Inc. agrees with NPCC on the following:
The term “Interconnected Transmission System” in Section iii,
bullet 4, is not clear. This is critical as it would affect the
redundancy requirement, especially to RAS installed only to
mitigate local BES issues.
The list in Attachment 1 should explicitly include arming
requirement and how it is achieved.
The Drafting team could consult NPCC Directory 7 including
Appendix B for a comprehensive list of parameters that are
reviewed for new/modified RAS.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
HQT agrees with the information required in Attachment 1 for review
purpose, with the following comments:
- Please clarify what is expected for “single component failure”. We
believe it should include only duplication of electrical components.
Please indicate that physical separation is not intended (such as a
tower carrying two communication links).
- Part II, 5th paragraph: the reference to TPL and to performance
requirements is not clear. We propose the following modification - “…
satisfies the voltage, frequency and stability performance requirements
of Table 1 of NERC Reliability Standard TPL-001-4 or its successor.” If
the intent of referring to P7 contingencies is the allowance for non-
consequential and firm load loss, this should be stated more explicitly in
the standard.
- Part III, 4th paragraph: please indicate clearly that this requirement
applies only to RAS needed to respect System performance under TPL001-4 contingencies, and not for all other RAS. There is some
confusion as to which RAS does this requirement apply to. Attachment
1 refers to TPL-001-4, but not the guidelines for Attachment 1, neither
does Attachment 2. Does this apply only to RAS installed to meet TPL?
This is how HQT interprets the current language. What about the RAS
installed to meet other NERC standards (FAC, TOP, ...) ? Clarification
is needed in the language used for this requirement. Depending on the
interpretation, the current language may read as if redundancy would
be required for RAS installed to meet regional requirements beyond
NERC TPL.
Document Name:
0
Likes:
0
Dislikes:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Answer Comment:
Texas RE is concerned that the UVLS standards will not capture UVLS
as UVLS program in the ERCOT interconnection and that the RAS
definition does not cover UVLS. Additionally, this standard only
mentions new or modified RAS and does not account for the fact that
RAS could be in place right now. Texas RE recommends clarify
regarding “reliability related need” as this statement is vague and could
lead to multiple interpretations.
Document Name:
0
Likes:
0
Dislikes:
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc.:
1) Requirement R1 currently requires the ‘RAS-entity’ to provide
the documentation in Attachment 1. The ‘RAS-entity’ term is a
very generic term as either the RAS-Owner or RAS-Planner
could be identified as a ‘RAS-entity’. The standard should be
more specific as to who should provide the information in
Attachment 1. The RAS-Owner can only provide the information
in Section I and Section III in Attachment 1. Section II should be
specific to the Transmission Planner/RAS-Planner as the RASOwner (Transmission Owner) does not have all the tools and
information to perform and provide the studies/documentation for
this section.
2) Attachment 1 is specific to identifying which documentation
should be provided by a RAS-entity. In the Implementation
(Section III) requirements, there is a requirement that states
documentation must be provided to show “that an appropriate
level of redundancy is provided…” If there is a requirement to
provide redundancy, it should be a separate requirement,
explicitly stated, and not reside in an Attachment outside of
Requirement R1, where this crucial detail could easily be missed.
3) The statement, “the RC may request additional information on
any reliability issue related to the RAS” should be moved from
Attachment 2 to Attachment 1.
4) The checklist particularly that in Attachment 1 should be
shortened and/or replaced by a simpler list. The reviewer (RC)
may further decide on the details.
5) Hydro One Networks Inc. agrees with NPCC on the following:
The term “Interconnected Transmission System” in Section iii,
bullet 4, is not clear. This is critical as it would affect the
redundancy requirement, especially to RAS installed only to
mitigate local BES issues.
The list in Attachment 1 should explicitly include arming
requirement and how it is achieved.
The Drafting team could consult NPCC Directory 7 including
Appendix B for a comprehensive list of parameters that are
reviewed for new/modified RAS.
Document Name:
0
Likes:
0
Dislikes:
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
We generally agree with the information required in Attachment 1, but
suggest the following changes:
Under Item II, second last bullet: revise “An evaluation indicating
that the RAS avoids adverse interactions with other RAS, and
protection and control systems.” to “An evaluation demonstration
that the RAS settings and operations are properly coordinated
with those of other RAS and protection and control systems”.
The SRC recommends that Requirement R2 be clarified to indicate
that the four month time period for RAS evaluations commences
when all information required by Attachment 1 is received. The
following clarification is suggested:
“For each RAS submitted pursuant to Requirement R1, each
reviewing Reliability Coordinator shall, within four full calendar
months of receipt of all information required to be provided to the
Reliability Coordinator in Attachment 1, or on a mutually agreed
upon schedule, perform a review of the RAS in accordance with
Attachment 2, and provide written feedback to the RAS‐entity…”
Document Name:
Answer Comment:
0
Likes:
0
Dislikes:
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Answer Comment:
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
Answer Comment:
Answer Comment:
• Should the first item in the Implementation Section clarify the
minimum level of control & monitoring to achieve adequate situational
awareness for the scheme?
Document Name:
0
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0
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
No
Answer Comment:
Requirement R4 requires the Transmission Planner to perform a
periodic evaluation of each RAS within its planning area at least once
every 60 calendar months. Attachment 1, section II, implies that the
Transmission Planner is involved in performing studies of each new or
functionally modified RAS before it is placed in service. We
recommend the SDT consider modifying Requirement R4 to clarify the
Transmission Planner’s role in studying new or functionally modified
RAS’s on an as needed basis in support of an RAS-entity’s need to
meet Requirement R1; or add a new requirement for the Transmission
Planner that addresses this pre-installation/modification role.
The submitting RAS-entity should also identify the TOP(s) and GOP(s)
that have been coordinated with during design of the RAS. We
recommend adding a check box prior to the last one in section II that
reads - “Identification of affected TOPs and/or GOPs”.
Document Name:
0
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0
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3.
Choice of Reliability Coordinator (Requirements R1, R2 and R3): Do you agree with the Reliability
Coordinator being the functional entity designated to review the RAS? If no, please provide the basis for
your disagreement, your choice of functional entity to conduct the reviews, and the rationale for your
choice.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Yes
Document Name:
0
Likes:
0
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Answer Comment:
Yes
Document Name:
Answer Comment:
0
Likes:
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
We would prefer that R2 (review the RAS) apply to the RCs and the
PCs that could be affected by the RAS. However, if the SDT wants R2
to apply to only one functional entity, then we accept the choice of the
RC, but suggest wording like, “each reviewing Reliability Coordinator, in
conjunction with applicable Planning Coordinators, shall . . . “ to
obligate the RC to obtain input from the PCs on the planning horizon
impacts of the RAS. RCs should be obligated to obtain input from
applicable PCs because they do not have the same knowledge and
capabilities of PCs to review the planning horizon impacts of a RAS.
Document Name:
0
Likes:
0
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Thomas Foltz - AEP - 5 -
Selected Answer:
Yes
Answer Comment:
AEP supports the choice of the RC to perform the
review, however we are concerned that the RC may not be far
enough removed from the RAS implementation process to be
considered completely impartial. In addition, they may not
possess the necessary expertise to adequately or thoroughly
review the RAS systems in the established time frame (4 months).
Document Name:
0
Likes:
0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
No
Answer Comment:
We do not see how the RC alone should be responsible for, or in some
cases capable of, fully evaluate the impacts of RASs. We see the need
to also involve the Planning Coordinator for assessing the
At present, the regions (primarily the RRO) have task forces or groups
made up of both operating and planning people from their members to
conduct this evaluation. The regions provide a thorough review of RASs
that are proposed by Asset Owners and Transmission Planners. We do
not see how either the RC or PC can provide this review in kind; in
other words, neither can fill in the blank vacated by the established
regional tasks forces or groups. Further, both have compliance
responsibilities: an RC must ensure the RAS meets its operating
standards requirements (less than a year; daily, weekly) and a PC must
ensure the RAS meets its planning standards requirements (greater
than a year). We therefore suggest the SDT to consider splitting the
evaluating requirements into the long-term planning timeframe
(assigned to the PC) and operations planning timeframe (assigned to
the RC).
Document Name:
0
Likes:
0
Dislikes:
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
Answer Comment:
ATC would prefer that R2 (review the RAS) apply to the RCs and the
PCs that could be affected by the RAS. However, if the SDT prefers R2
to apply to only one functional entity, then ATC accepts the choice be
the RC, but recommends wording like, “each reviewing Reliability
Coordinator, in conjunction with applicable Planning Coordinators, shall
. . . “ to obligate the RC to obtain input from the PCs on the planning
horizon impacts of the RAS. RCs should be obligated to obtain input
from applicable PCs because RCs do not have the same knowledge
and capabilities of PCs to review the planning horizon impacts of a
RAS.
Document Name:
0
Likes:
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
No
Dominion believes that RAS should be reviewed and approved in both
the planning and operating horizons by designated entities within
whose area(s) the Facility (ies) the RAS is designed to protect reside.
Dominion could have supported the recommendation contained in the
SCPS Technical designating the RC and the PC, but a review of the
most recent NCR Active Entities List indicates no entity is registered as
PC. For this reason, we chose to recommend the TP instead of the PC.
Document Name:
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0
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Answer Comment:
0
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
Comments: PacifiCorp does not agree with the RC being the functional
entity designated to review the RAS. PacifiCorp believes that RAS
review should be undertaken by the planning coordinator, the
transmission planner and neighboring transmission planners as they
are the parties that possess the requisite knowledge to make a
determination as to the appropriateness of the RAS.
0
Likes:
0
Dislikes:
Jared Shakespeare - Peak Reliability - 1 -
Document Name:
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Yes
The RC should also include the Planning Coordinator in the review of
the RAS. The RC does not possess adequate capabilities to review the
RAS in the Planning Horizon.
Document Name:
Likes:
0
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Answer Comment:
0
Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Answer Comment:
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
No
Answer Comment:
ERCOT is concerned that the placement of responsibility to evaluate
the impacts of RASs on the RC alone may ignore current, effective
processes as well as the current responsibilities of the Planning
Coordinator. Thus, ERCOT respectfully suggests that the SDT assess
the effectiveness of the current processes and evaluate how such can
be incorporated into the proposed Standard. In the alternative, the SDT
should evaluate the need to involve the Planning Coordinator in the
evaluation of the impacts of RASs. More specifically, at present, the
regions (primarily the RRO) have task forces or groups made up of both
operating and planning personnel from their members to conduct
evaluations of proposed and modified RASs. Through these task forces
or groups, a thorough review of RASs that are proposed by Asset
Owners and Transmission Planners is performed. As current processes
involve both real-time operations and planning function personnel, it is
unlikely that either entity in isolation can fill in the gap that would be
created once the established regional tasks forces or groups vacate
their responsibilities under the RRO. Further, both the RC and the PC
have existing compliance responsibilities associated with RASs: an RC
must ensure the RAS meets its operating standards requirements (less
than a year; daily, weekly) and a PC must ensure the RAS meets its
planning standards requirements (greater than a year). ERCOT,
therefore, suggests that, in the event that current processes cannot be
relied upon or incorporated into the proposed standard, the SDT, at a
minimum, consider revising the requirements to ensure that any RAS
evaluations performed by the RC are done in coordination with the PC
such that evaluations that are performed account for both the long-term
planning timeframe and operations planning timeframe.
Document Name:
0
Likes:
0
Dislikes:
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
No
RCs need to be aware of all SPSs in their footprint and would be a
logical entity to take over the RRO’s responsibility for maintenance of a
SPS database. However given the wide-area impacts of RAS, the
technical reviews and verification of proper operation should be done in
a collaborative forum.
Likes:
0
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Document Name:
Answer Comment:
0
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
No
The type of review envisioned by these standard requirements are
significantly and inappropriately broader than the responsibilities and
functions of the Reliability Coordinator as laid out in the NERC
Functional Model. In addition to conflicting with the functional model,
the tools, breadth of study and coordination envisioned by these
requirements would require many of the Reliability Coordinators to
acquire new tools, study capabilities and resources to achieve the
desired reviews. Finally, these new responsibilities for the RCs would
become duplicative with the current, and appropriate practice of
studying RAS installation and effectiveness in a Regionally coordinated
manner across the Planning Horizons. Subject matter expertise for the
type of studies needed to evaluate RASs resides in the planning tools
and horizon as the issues that require RASs are usually identified in the
planning horizon. Regional Entities could perform the “independent”
reviews as they have the expertise being used today to perform the
reliability assessments of each Region.
Document Name:
Answer Comment:
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The NERC Functional Model defines the RC as being “The functional
entity that maintains the Real-time operating reliability of the Bulk
Electric System within a Reliability Coordinator Area.” It is not
responsible for the planning or installation of a Protection System. The
NERC Functional Model does not support the RC as being the
reviewer. The RC does not review nor have the approval authority over
any other facility or protection system installation.
A RAS needs to be categorized based on impact to facilitate who
approves. A RAS that impacts one Transmission Planner only would
be coordinated and approved by that Transmission Planner. A RAS that
impacts multiple Transmission Planners would be referred to the
Planning Coordinator that the Transmission Planners report to in the
functional model. Where multiple Planning Coordinators are impacted,
then suggest following the PRC-006 (UFLS) approach and require
coordination of studies.
Document Name:
0
Likes:
0
Dislikes:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Since approval of the installation of a RAS involves performing planning
studies, we believe the Planning Coordinator should be the entity
responsible for reviewing and approving RAS. We certainly agree the
RC should be made aware of new RAS but believe they do not have
the responsibility to approve the RAS since they are the operating
entity. We view this no different than planning a new transmission line
and associated Protection Systems which are performed by the
Planning Coordinator.
Likes:
0
Dislikes:
Document Name:
Answer Comment:
0
Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
David Jendras - Ameren - Ameren Services - 3 -
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Answer Comment:
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc.:
1) The majority, if not all, the supporting documentation required
in Attachment 1 is based on NERC standards PRC-012-0/1,
PRC-013 and PRC-014. These standards were all ONLY
applicable to the Regional Reliability Organization (RRO). RRO
organizations already have established programs, standards,
directories and procedures in place that request this information
from RAS-entities. RRO is the most experienced in performing
reviews of the requested documentation and this system has
already been in place for years. The RRO should be functional
entity designated to review the RAS.
2) The SDT has suggested that the RC has the option of having
another entity (e.g. Regional Entity) review the RAS. This should
be reflected in R2.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
Although HQT understands the SDT’s motivation for suggesting a
NERC functional entity instead of the RRO for the review requirements,
HQT disagrees that the RC meets the criteria for a third-party
independent review with expertise in planning, operation, protection,
etc. No single NERC functional entity is adequate for performing the
review by itself. The existing RROs’ processes (NPCC, WECC, …)
definitely meet the criteria for a thorough and rigorous review with
multiple RCs, TPs, TOPs and much wider and independent field of
expertise than a single RC.
Since there seems to be an opening within the standard (R2 rationale)
to allow the RC to delegate this task to a third-party (e.g. the RROs
current process), HQT would support this approach. However, it seems
like going through the RC to obtain a review by the RRO is somewhat
“fill in the blank” and administrative with no improvement in reliability.
Because of the importance of reliability for RROs and the existing
process for RAS review, the SDT should consider keeping the
requirements for submitting a RAS for review (R1) assigned to the RAS
entity, and simply state that the submission for review should be made
to the RRO. In this case, R1 and R3 would still be applicable to the
RAS-entity for the submittal for review by and approval by the RRO
prior to placing RAS in service. The current R2 applicable to the RC
could be removed.
Document Name:
Likes:
0
Dislikes:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Texas RE is concerned with how the information to evaluate RAS will
be provided to the Transmission Planner or Planning Coordinator.
Document Name:
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc.:
1) The majority, if not all, the supporting documentation required
in Attachment 1 is based on NERC standards PRC-012-0/1,
PRC-013 and PRC-014. These standards were all ONLY
applicable to the Regional Reliability Organization (RRO). RRO
organizations already have established programs, standards,
directories and procedures in place that request this information
from RAS-entities. RRO is the most experienced in performing
reviews of the requested documentation and this system has
already been in place for years. The RRO should be functional
entity designated to review the RAS.
2) The SDT has suggested that the RC has the option of having
another entity (e.g. Regional Entity) review the RAS. This should
be reflected in R2.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Using the criteria outline by the SDT in its recent webinar, in addition to
the independence of the reviewer and geographic span, the team also
mentioned “expertise in planning, protection, operations,
equipment”. The attributes of this expertise to the level expected do not
currently exist in most RC organizations. RC’s are primarily operating
entities (and even then primarily in real-time) and not experts in
planning (beyond the operating time frame), protection or
equipment. Transmission Owners, Transmission Operators and
Transmission Planners normally have that expertise. The FERC
acknowledged the limited RC technical expertise in evaluating details of
restoration plans in its Order 749, Paragraph 38 (“…basis on which a
reliability coordinator rejects a restoration plan will necessarily be based
on generic engineering criteria…”). The review of a RAS by an RC
should not be held to a higher expectation due to similar limited
expertise with the equipment and systems involved in a RAS.
The “flexibility” for the RC granted in the requirement to designate a
third party would seem to immediately invalidate the original
assumptions that the RC has the compelling capability to adequately
perform the review while meeting the SDT’s characteristics of the
reviewing entity. To allow this, while still requiring the RC to be
responsible for the review, seems like an improper administrative
burden and a potential compliance risk that the RC may assume
because it had to find an entity more qualified than itself to perform the
review. If an RC is not qualified to review all of the items in Attachment
2 then how can it be held responsible for the results of the review?
Regarding the designation of a third party reviewer, clarification needs
to be made regarding what it means to “retain the responsibility for
compliance.” Does this simply mean that the review takes place or that
there is some implied resulting responsibility for the correct design and
implementation that the RC is now accountable for.
Finally, also regarding the designation of a third party reviewer, is the
term “third party” meant to be any entity not involved in the planning or
implementation of the RAS?
The alterative to using the RC? Although there appears to be a
movement to remove the RRO as a responsible entity from all
standards, those organizations through their membership expertise and
committee structures more closely match the characteristics stated by
the SDT – expertise in planning/protection/operations/equipment,
independence by virtue of the diversity of its members, wide area
perspective, and continuity. If for some reason the SDT, believes that
the RRO still should not be involved then an alternative could be the
Planning Coordinator function which should have similar expertise to
the Transmission Planners that are to specify/design a RAS per the
functional model yet would have some independence which the SDT is
looking for.
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
We do not see how the RC alone should be responsible for, or in
some cases capable of, fully evaluating the impacts of RASs. We
see the need to also involve the Planning Coordinator for
assessing the RAS. At present, the regions (primarily the RRO)
have task forces or groups made up of both operating and
planning people from their members to conduct this evaluation.
The regions provide a thorough review of RASs that are proposed
by Asset Owners and Transmission Planners. These processes
should be retained and the proposed requirements should not
preclude these to continue.
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0
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
Document Name:
0
Likes:
0
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
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0
Dislikes:
4.
Checklist in Attachment 2 (Requirement R2): Do you agree that the checklist in Attachment 2
provides a comprehensive guide for the Reliability Coordinator to facilitate a thorough RAS review? If no,
please identify what other reliability-related considerations should be included in Attachment 2 and the
rationale for your choice.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
Document Name:
0
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0
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
Answer Comment:
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0
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0
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
The paragraph, “RAS retirement reviews may use an abbreviated
format that concentrates on the Planning justifications describing why
the RAS is no longer needed. Implementation issues will seldom
require removal review” is confusing. Consider the following wording,
“may be shorter and simpler. Few, if any, of the Design and
Implementation checklist items will apply to a RAS retirement review. A
retirement review should primarily assure that there is adequate
Planning justifications regarding why the RAS is no longer needed.”
We suggest that R4 return to the 5-year requirement versus the 60 full
calendar month. There is no additional reliability benefit to specifying
60 months versus once at least every 5 calendar years. However,
there is a scheduling benefit to once at least every 5 calendar
years. The 5 calendar year option allow for flexibility with no reduction
in reliability. It is reasonable for any requirement spanning two or more
years to use “annual calendar years”. For requirements that are less
than two years, calendar month(s) is more appropriate.
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Answer Comment:
Thomas Foltz - AEP - 5 -
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0
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0
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Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
We generally agree with the proposed guideline presented in
Attachment 2, but have difficulty understanding the first bullet which
reads: “frequency‐related instability” In fact, if we apply our
interpretation correctly that it means instability caused by frequency
excursion or collapse or generator instability, then this term will
eliminate the possibility of instability caused by voltage collapse. We
suggest to replace this term with “system instability” which should cover
all instability cases.
Document Name:
Answer Comment:
0
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0
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Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Yes
However, in Attachment 2, the paragraph, “RAS retirement reviews may
use an abbreviated format that concentrates on the Planning
justifications describing why the RAS is no longer needed.
Implementation issues will seldom require removal review” is confusing.
For clarity, ATC recommends rewording, such as “may be shorter and
simpler. Few, if any, of the Design and Implementation checklist items
will apply to a RAS retirement review. A retirement review should
primarily assure that there is adequate Planning justifications regarding
why the RAS is no longer needed.”
Document Name:
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0
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0
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Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
Document Name:
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0
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Answer Comment:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
No
Dominion believes “frequency‐related instability” is not a universally
defined/accepted term. Instead, consider referencing specifically PRC006 attachment 1 or 1A.
0
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Document Name:
Answer Comment:
Selected Answer:
Yes
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
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Answer Comment:
0
Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
No
Standards are meant to be clear and defined. However, this checklist
introduces ambiguity. There are implications of redundancy, but more
clarity is needed. Further, the level of review required by the RC is too
subjective. What distinguishes "significant" from "lesser impact?"
The second-to-last bullet in the Design section should be clarified
because it's difficult to understand.
The last bullet in the Design section should be deleted because future
system planning is the TP/PC function and not an RC function.
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Answer Comment:
0
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
Questions 5 and 6 pertain to these topics.
Document Name:
Answer Comment:
0
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0
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Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Yes
Answer Comment:
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
Questions 5 and 6 pertain to these topics.
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0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
Document Name:
0
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0
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Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
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0
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
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0
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0
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
While ERCOT is not opposed to a guideline regarding the performance
of RAS evaluations, Attachment 2 is overly prescriptive and does not
allow for RCs to utilize their operational experience and engineering
judgment. ERCOT recommends that the introductory paragraph to
Attachment 2 be revised to provide greater flexibility regarding RAS
evaluations. The following revisions are suggested:
The following checklist provides reliability related considerations for the
Reliability Coordinator to consider for inclusion in its evaluation for each
new or functionally modified2 RAS. The RC should utilize the checklist
to determine those considerations that are applicable to the RAS
evaluation being performed; however, RAS evaluations are not limited
to the checklist items and the RC may request additional information on
any reliability issue related to the RAS
ERCOT also supports the SRC comments regarding Requirement R2.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
No
See Duke Energy’s attachment for suggested revisions to
Attachment 2.
PRC-012-2_AHM_Attachment 2 RC RAS Review
Checklist_WTL_JSW_edits_18MAY2015.docx
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0
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Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
Questions 5 and 6 pertain to these topics.
Document Name:
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0
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0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
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0
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0
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Answer Comment:
Selected Answer:
No
Answer Comment:
We agree that the list is a comprehensive guide, but do not believe this
should be done solely by the RC.
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0
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0
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Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
See comment to number 3 that disagrees with the RC being the
appropriate reviewer.
Document Name:
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
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Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
In the Determination of Review Level, the three conditions listed can
occur at any time for the failure of a RAS to operate or operate
inadvertently, thereby mandating that the entire checklist be followed.
Attachment 2 states that the level of review may be limited if the system
response for failure of the RAS to operate or inadvertent operation of
the RAS does not result in certain significant conditions.
However, Attachment 2 does not explicitly describe what portions of
Attachment 2 would be considered a limited review. It only states that if
certain operating conditions are possible as the result of the failure to
operate or inadvertent operation then the entire Attachment 2 checklist
should be followed.
It must be recognized that the conditions in Attachment 2 are too broad
for determining whether a full-scale or limited review is required.
Specifically, the standard should quantify the load in the condition
“unplanned tripping of load or generation.” This condition captures
tripping of ultimately even very small generators and loads, i.e. the
anticipated impact does not correlate with the required depth of the
review. It is suggested to consider modification of this particular
condition.
Elimination of Attachment 2 should be considered. The Planning Entity
and Transmission Owner has the expertise per the Functional Model to
develop a RAS.
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analysis) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
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0
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0
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
No
Tri-State recommends changing the “Determination of Review Level”
section to read:
“The RC is allowed some latitude in the depth of their review based on
the individual Remedial Action Scheme’s complexity and
implications. Nevertheless, the RC shall follow the entire checklist
should the RAS:
• Impact the ability of the BES to operate within established IROLs
• Contribute to or have the potential to cause wide-area:
◦ cascading of transmission facilities;
◦ uncontrolled separation;
◦ voltage instability; or
◦ frequency instability. “
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0
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Answer Comment:
0
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
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0
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0
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Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
We agree Attachment 2 represents a comprehensive list of information
for a higher level reliability authority to review. However, we believe the
PC should be performing the review.
0
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0
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
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Answer Comment:
Selected Answer:
Yes
Document Name:
0
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0
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David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Yes
Answer Comment:
Answer Comment:
We request to add “pursuant to Requirement R2” after ‘review’ in
the opening paragraph so that it reads “The following checklist
identifies important reliability related considerations for the
Reliability Coordinator to review pursuant to Requirement R2 and
verify for each new or functionally modified RAS.” This matches
the Attachment 1 wording.
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0
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0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
Answer Comment:
Document Name:
Likes:
1
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Attachment 2 seems redundant with Attachment 1. The SDT should
consider merging them together and referring to a single attachment for
the key items to submit for review and review checklist of those items.
The section “Determination of Review Level” needs some clarification.
What is a “limited review”? What items from the checklist can be
skipped in this case? At a minimum, some guidelines should be added.
Likes:
0
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Document Name:
Answer Comment:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Document Name:
0
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0
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Answer Comment:
Selected Answer:
No
Answer Comment:
Texas RE is concerned that UVLS will not be considered. Project
2008-02.2 UVLS indicates in the technical guide that certain UVLS will
not be in a UVLS Program but would be considered a RAS but it does
not appear that UVLS is considered part of RAS. The entire checklist
should be used for voltage-related instability.
Document Name:
0
Likes:
0
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
Document Name:
0
Likes:
0
Dislikes:
Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
We generally agree with the proposed guideline presented in
Attachment 2, but have difficulty understanding the first bullet
which reads: “frequency‐related instability” In fact, if we apply our
interpretation correctly that it means instability caused by
frequency excursion or collapse or generator instability, then this
term will eliminate the possibility of instability caused by voltage
collapse. We suggest to replace this term with “system instability”
which should cover all instability cases.
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
Document Name:
0
Likes:
0
Dislikes:
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
BPA requests clarification of Attachment 2 Reliability Coordinator RAS
Review Checklist, Implementation, bullet six: RAS automatic arming, if
applicable, has the same degree of redundancy as the RAS. What is
meant by “the same degree of redundancy”?
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Answer Comment:
0
0
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Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
By definition though, any RAS that is designed to trip load or generation
would require a full review since an "inadvertant operation of the RAS"
WOULD result in unplanned tripping of load or generation. What then
would constitute a scheme that could be reviewed to a lesser degree?
Likes:
0
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Document Name:
Answer Comment:
0
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Answer Comment:
Document Name:
0
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0
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5.
Choice of Transmission Planner (Requirement R4): The Transmission Planner is required to perform
a technical evaluation (planning analyses) of each RAS at least once every 60 full calendar months to
verify the continued effectiveness and coordination of the RAS, as well as the BES performance following
an inadvertent operation of the RAS. Do you agree with the Transmission Planner being the functional
entity designated to evaluate the RAS? If no, please provide the basis for your disagreement, your choice
of functional entity to conduct the evaluations, and the rationale for your choice.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Yes
Document Name:
0
Likes:
0
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John Fontenot - Bryan Texas Utilities - 1 -
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Answer Comment:
We suggest that R4 (evaluate the RAS) require the TP to obtain input
from affected TOPs and RAS-owners as part of the RAS evaluation
with wording like, “Each Transmission Planner, in conjunction with
affected Transmission Operators and the RAS-owner, shall . . .“
Affected TOPs have knowledge and capabilities to assess
the operating horizon impacts of a RAS that TPs do not have. In the
same vain, RAS-owners have more knowledge of the design and
purpose of the RAS that TPs.
We suggest changing the word “applicable” to “affected” in the
comment above to clarify only “affected” TOP’s and RAS owners need
to submit input or participate in the review.
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0
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0
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Selected Answer:
Answer Comment:
Thomas Foltz - AEP - 5 -
Document Name:
0
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0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
No
At present, many Transmission Owners are also registered as the
Transmission Planners (for the assets that the TOs own). A proper
evaluation of the RAS should be performed by an entity that is either
not also the TP or has a wider perspective than the TP. We believe a
PC is more suitable to perform this task than the TP, and therefore
suggest replacing the TP with the PC.
Document Name:
Answer Comment:
0
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0
Dislikes:
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
ATC recommends that R4 (evaluate the RAS) require the TP to obtain
input from affected TOPs and RAS-owners as part of the RAS
evaluation and reword as follows: “Each Transmission Planner, in
conjunction with affected Transmission Operators and the RAS-owner,
shall . . . “. Affected TOPs have knowledge and capabilities to assess
the operating horizon impacts of a RAS that TPs do not have. In the
same vain, RAS-owners have more knowledge of the design and
purpose of the RAS that TPs.
Likes:
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Answer Comment:
0
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
No
Dominion believes that RAS should be reviewed and approved by both,
the RC and the TP within whose area(s) the Facility (ies) the RAS is
designed to protect reside.
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
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0
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Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
No
Why does the RC perform the initial review and then the TP performs
subsequent reviews? This does not follow the philosophy of an
independent reviewer.
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0
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Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
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0
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0
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Yes
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0
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0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
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0
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0
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Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Answer Comment:
Answer Comment:
Yes
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0
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0
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Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
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0
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0
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
No
At present, many Transmission Owners are also registered as the
Transmission Planners (for the assets that the TOs own). Although it is
clear that such an entity would have greater expertise regarding the
function of the RAS, such evaluations should also be coordinated with
and reviewed by the applicable PC. Such coordination and review
would allow PCs to ensure that the assessment of the impact of RASs
accounts for the broader system perspective and
characteristics. ERCOT recommends that the Requirement R4 be
modified to ensure that assessments performed by the Transmission
Planner are coordinated with or reviewed by the applicable PC.
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0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
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0
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Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Answer Comment:
Selected Answer:
Yes
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0
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0
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Answer Comment:
Yes
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Answer Comment:
0
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0
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Yes
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0
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0
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
Yes
Yes – however the Planning Authority should be involved in the
evaluation as they are better positioned to study, identify and
coordinate potential impacts on areas where multiple TPs are involved
or potentially impacted.
1
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Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
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Answer Comment:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
Yes
In Requirement R4, the draft standard establishes Transmission
Planners as being responsible for performing evaluations of each RAS
in its planning area. However, a mechanism/requirement for providing
the TP with the required information from the Reliability Coordinator is
not defined. Suggest rewording R4 to:
R4. Each Transmission Planner shall perform an evaluation of
information provided by the Reliability Coordinator for each RAS within
its planning area at…
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0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
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0
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0
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
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Selected Answer:
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0
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0
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Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
We disagree with the TP being the entity responsible to evaluate the
RAS. Final review and approval should be the responsibility of the
highest level planning authority which is the Planning Coordinator. This
is consistent with the functional model. In those areas, where there is
not a Planning Coordinator, the Transmission Planner could be
substituted and actually represents the reality that the Transmission
Planner is really serving as the Planning Coordinator anyway.
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0
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0
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
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0
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0
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David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Yes
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0
0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
Answer Comment:
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1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
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Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
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0
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0
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Answer Comment:
Yes
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0
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0
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Texas RE recommends adding clarity for submitting data to the
Transmission Planner, as there is no specific requirement to do
so. R11 states that if an entity receives a request with a “reliability
related need” the RAS-entity shall provide the information. Texas RE
recommends adding clarity to “reliability related need”.
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0
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
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0
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0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
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0
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
No
Answer Comment:
Answer Comment:
For the ERCOT Interconnection, CenterPoint Energy believes the PC
should be the designated functional entity to evaluate the RAS as
described in Requirement R4 in the preliminary draft of PRC-0122. ERCOT ISO presently performs this function and is best positioned
to see the wide-area view in the ERCOT planning area. The
established regional rules detail ERCOT ISO’s evaluation which is
performed at least every 60 months, as Requirement R4 is currently
drafted. Section 11.2 ‘Special Protection System’ of the ERCOT Nodal
Operating Guides is attached for reference.
CenterPoint Energy suggests the following options to address
evaluation of the RAS within the ERCOT Interconnection:
1. Change Transmission Planner to Planning Coordinator in
Requirement R4. (preferred option)
2. Add “Planning Coordinator – ERCOT Interconnection” in the
Applicability section and revise the beginning of Requirement R4 to
state “Each Transmission Planner or Planning Coordinator shall
perform an evaluation….”
3. Add a regional variance in PRC-012-2 for the ERCOT
Interconnection.
Document Name:
Section 11.2_Special Protection System_ERCOT Nodal Operating
Guides_20140401.docx
0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
No
At present, many Transmission Owners are also registered as the
Transmission Planners (for the assets that the TOs own). A proper
evaluation of the RAS should be performed by an entity that is
either not also the TP or has a wider perspective than the TP. We
believe a PC is more suitable to perform this task than the TP, and
therefore suggest replacing the TP with the PC.
Note - These SRC comments represent a consensus of the
ISOs/RTOs with the exception of ERCOT.
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0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
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0
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0
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
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0
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Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
Answer Comment:
Is the expectation that the Transmission Planner fill out
(update) Attachment 1 as part of it's review? As Attachement 1 is
currently written, it appears that Attachment 1 is only filled out for new
or functionally modified schemes. I can see that new or modified
schemes are designed to avoid the single component failure, however
"grandfathered" schemes that are still needed and still effective as is
could be missed.
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Yes
Answer Comment:
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0
6.
No RAS Classification (Requirement R4): The drafting team considered the RAS classification
systems used by several Regions to be rooted in PRC-012, Requirement R1, R1.4. which reads:
“Requirements to demonstrate that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the contingency for which it was
designed, and not exceed TPL-003-0.” Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is retained in Requirement 4 and Attachment
1. Do you agree that the language of Requirement R4, its Parts, and Attachment 1 accomplish the
objectives of RAS “classification” without having a formal RAS classification system in the standard? If
no, please provide the basis for your disagreement and describe an alternate proposal.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
No
We agree that the parts of R4 include reasonable aspects of the RAS to
evaluate, but the RAS “classification” should be based on the RAS
definition. For R4.3, we propose replacing “satisfies the requirements of
Category P7 in Table 1 of NERC Reliability Standard TPL-001-4, or its
successor” with “is allowed to result in an interruption of firm
Transmission Service or Non-Consequential Load Loss”. This wording
is simpler and more straightforward and would not be subject to change
if a successor of TPL-001-4 does not a Category P7, changes the
Category P7 contingency, or changes the associated performance
requirements.
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Thomas Foltz - AEP - 5 -
Selected Answer:
Yes
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0
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Leonard Kula - Independent Electricity System Operator - 2 -
Answer Comment:
Selected Answer:
No
Answer Comment:
In the absence of the classification and minimum design requirements
there will be risks for some RAS to be under or overdesigned subject to
personal interpretation of the standard.
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0
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Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
Answer Comment:
ATC agrees that the parts of R4 includes reasonable aspects of the
RAS to evaluate, but the RAS “classification” should ultimately be
based on the RAS definition. For R4.3, ATC proposes to replace
“satisfies the requirements of Category P7 in Table 1 of NERC
Reliability Standard TPL-001-4, or its successor” with rewording such
as, “is allowed to result in an interruption of firm Transmission Service
or Non-Consequential Load Loss”. This wording is simpler and more
straightforward and would not be subject to change if a successor of
TPL-001-4 does not include a Category P7, changes the Category P7
contingency, or changes the associated performance requirements.
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Brian Bartos - CPS Energy - 3 -
Selected Answer:
Answer Comment:
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Yes
0
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0
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Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
0
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
No
Requirement R4 mandates the Transmission Planner perform a
technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and
coordination of the RAS, as well as the BES performance following an
inadvertent operation of the RAS.
The drafting team considered the RAS classification systems used by
several Regions to be rooted in PRC-012, Requirement R1, R1.4.
which reads: “Requirements to demonstrate that the inadvertent
operation of a RAS shall meet the same performance requirement
(TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the
contingency for which it was designed, and not exceed TPL-003-0.”
Although, the drafting team is not proposing to use formal RAS
classifications, the intent of PRC-012, Requirement R1, R1.4. is
retained in Requirement 4 and Attachment 1.
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Answer Comment:
0
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Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
No
The Standard should classify RAS because the current language will
lead to subjectivity, ambiguity, and disagreements between RCs and
RAS-entities. This will lead to inconsistent application for appropriate
levels of security, dependability, and redundancy and the associated
level of review required. If a RAS is not classified, these issues (i.e. in
the sentence above) become too subjective. It is current practice in the
industry to have various classifications for this very
purpose. Dependability and security are not defined terms in the NERC
glossary.
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Answer Comment:
0
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Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirement R6 mandates each RAS-owner analyze each RAS
operation or failure of a RAS to operate to identify performance
deficiencies. Question 7 pertains to Requirement R6.
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0
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Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
No
Answer Comment:
There does not seem to be any sort of differentiation for the design
requirements of various RAS. It is a one-size-fits-all approach;
therefore there really are no different categories.
While not specifically reference, the third checkbox in Attachment 2,
Implementation, will require every RAS to be fully redundant. Is says
that with a single component failure, the BES must meet the same
requirements that drove the need for the RAS. Even if failure of the
RAS has minimal impact, failure of the RAS would cause the BES not
to meet performance requirements or the RAS wouldn’t have been
needed.
Requirement R6 mandates each RAS-owner analyze each RAS
operation or failure of a RAS to operate to identify performance
deficiencies. Question 7 pertains to Requirement R6.
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0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Yes
SPP has a small number of RAS and doesn’t have much input on the
concept of RAS “classification”.
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Answer Comment:
0
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Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Is the intent of this standard to create projects or Contingency plans to
mitigate RAS misoperations?
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Answer Comment:
0
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
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0
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0
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
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0
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0
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
R4.3 makes reference to performance requirements of Category P7
in Table 1 of NERC Reliability Standard TPL-001-4, or its
successor. Can we infer that those performance requirements are
the same as in Category P2-4 and Category P4-6?. This
requirement could be quite difficult to test depending on the type
of RAS.
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0
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Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Answer Comment:
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0
0
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
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0
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0
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Answer Comment:
Selected Answer:
Yes
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0
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0
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Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Answer Comment:
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0
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0
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Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Without defined “classifications”, all RAS require the same attention by
the standard’s requirements.
It seems the ‘Determination of Review Level’ in Attachment 2 also
accomplishes the objectives of RAS classifications by determining the
level of system response (i.e. determining Significant vs. Limited).
However, the language of Requirement R4 and Attachment 1 (and
Attachment 2 as indicated in the comment preceding) accomplish the
objectives of RAS classification without having a formal RAS
classification system.
This is particularly important to regions that already employ a
classification system, thereby avoiding multiple and overlapping
classifications.
A classification system is needed to easily communicate the risk and
impact of a RAS. Classification, if included in the database, would
facilitate an understanding of the risk posed by the various RAS
schemes deployed in the BES. Without a classification system for
RAS, all RASs are treated equally; this gives the RC (or whomever is
eventually assigned responsibility for evaluating them) too much
latitude in interpreting an adequate level of redundancy, which would
almost invariably lead to inappropriate design.
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0
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0
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
No
Answer Comment:
Tri-State has three concerns here.
First, “planning area” is not defined. We recommend changing the first
sentence of R4 to:
“Each Transmission Planner shall perform an evaluation of each
RAS for which they have planning responsibilities at least
once
every…”
Second, it is not clear what is meant by “inadvertent operation of the
RAS”. RASs commonly operate more than one facility (see WECC
RAS-1). Does this mean the entire RAS or each individual
component?
Third, Tri-State also do not agree with the criteria that inadvertent
operation of the RAS must satisfy the same performance requirements
as those required for the contingency for which it was designed. There
are existing RASs that could not meet this requirement.
For example, there are Generator Owners that elect to install RASs that
trip (verses re-dispatch) their generator(s) to prevent overloading
transmission lines following a single element outage in lieu of upgrading
the transmission network. TPL-001-4 does not allow interruption of
Firm Transmission Service for P1 contingencies. Since this type of
RAS is to mitigate a P1 caused overload, inadvertent operation of the
RAS cannot interrupt Firm Transmission Service either. This would not
meet the criteria that the RAS must satisfy the same performance
requirements as those required for the contingency for which it was
designed.
To address the second and third concerns above, Tri-State
recommends simplifying R4.3 to:
“The inadvertent operation of any portion of the RAS does not cause a
violation of an established Operation’s or Planning horizon System
Operating Limit.“
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
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0
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0
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Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
We do not believe it is necessary to classify RAS. RAS is a defined
term that should clearly identify the vast majority of RAS. If a regional
entity, Planning Coordinator, or Reliability Coordinator wants to
continue classifying and tracking RAS, there is nothing in the standard
that prohibits this even though it is not necessary for reliability.
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Answer Comment:
0
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0
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
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0
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0
David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Yes
Document Name:
0
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0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Answer Comment:
Selected Answer:
No
Answer Comment:
1) Hydro One Networks Inc.:Regions or individual RCs could
have their internal/regional Typing, with different design
requirements for different Types.
2) Hydro One Networks Inc. agrees with NPCC on the following:
Without a classification system for RAS, all RASs are treated
equally; this gives the RC (or whoever is responsible for
evaluating) too much latitude in interpreting an adequate level of
redundancy, which could easily lead to an inappropriate RAS
design.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
HQT proposes that requirements for redundancy, testing and
maintenance be different for “limited-impact” RAS versus “high impact”
RAS. HQT believes that the standard shall retain the following
recommendation from the SPCS report: …it may be appropriate to
establish less stringent requirements pertaining to monitoring or single
component failure of SPS that present a lower reliability risk. This
recommendation is aligned with industry practice. Some RAS are
installed for NERC standard compliance, but their impact is very limited
to a contained area. Other RAS are critical so wide-area problems for
which a much higher reliability of the RAS needs to be achieved
through more rigorous design (redundancy and security), maintenance
and testing.
HQT agrees with the removal of a formal classification from a NERC
standpoint, allowing the regions flexibility to have their own
classification. However, regarding the performance for inadvertent
operation, requirement 4.3 and Attachment 1 do not provide any
consideration of security in the implementation.
If redundancy is an appropriate measure to demonstrate that failure of a
single component does not prevent from meeting the TPL standards
requirements through the design of a RAS, then it should be possible to
demonstrate that inadvertent operation of a component of a RAS does
not prevent from meeting P7 from TPL 001-4 through the design
review. In that sense, the R3 rationale states that “The review by the
RC is intended to identify reliability issues that must be resolved before
the RAS can be put in service. The reliability issues could involve
dependability, security, or both. A more detailed explanation of
dependability and security is included in the Supplemental Materials
section of the standard.” No further reference to security is made
anywhere in the standard. As for the single component failure
requirement, the inadvertent operation requirement should be linked to
the design of the RAS.
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0
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Requirement R6 mandates each RAS-owner analyze each RAS
operation or failure of a RAS to operate to identify performance
deficiencies. Question 7 pertains to Requirement R6.
Document Name:
Answer Comment:
0
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0
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
Answer Comment:
Texas RE recommends changing the phrase “avoids adverse
interactions” to something less vague.
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0
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0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
1) Hydro One Networks Inc.:Regions or individual RCs could
have their internal/regional Typing, with different design
requirements for different Types.
2) Hydro One Networks Inc. agrees with NPCC on the following:
Without a classification system for RAS, all RASs are treated
equally; this gives the RC (or whoever is responsible for
evaluating) too much latitude in interpreting an adequate level of
redundancy, which could easily lead to an inappropriate RAS
design.
Document Name:
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0
0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirement R6 mandates each RAS-owner analyze each RAS
operation or failure of a RAS to operate to identify performance
deficiencies. Question 7 pertains to Requirement R6.
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0
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Answer Comment:
0
Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirement R6 mandates each RAS-owner analyze each RAS
operation or failure of a RAS to operate to identify performance
deficiencies. Question 7 pertains to Requirement R6.
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0
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0
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
No
Answer Comment:
Answer Comment:
Attachment 2 generally accomplishes the objective of RAS
“classification.” However, confirmation by the drafting team is
requested that “unplanned tripping of load or generation” refers to
tripping of load or generation beyond that identified for another
contingency (e.g., breaker failure or bus Fault) as opposed to simply
unintentional or inadvertant tripping.
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0
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0
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
7.
RAS Operational Analyses (Requirement R6): Requirement R6 mandates each RAS-owner analyze
each RAS operation or failure of a RAS to operate to identify performance deficiencies Do you agree that
the application of Requirement R6 and its Parts would identify performance deficiencies in RAS? If no,
please provide the basis for your disagreement and an alternate proposal.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
No
See response to Question #8.
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0
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0
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John Fontenot - Bryan Texas Utilities - 1 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
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0
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
We agree that the application of R6 would identify deficiencies, but
there is a disconnect between the Rationale Box and R6. The
Rationale Box says RAS operations and Mis-operations “should” be
analyzed while R6 states they “shall” be analyzed. The Rationale Box
should be revised to state that RAS Operations and Mis-operations
must be analyzed.
The analysis of the RAS and identification performance deficiencies
would need to include the contribution of RAS-owners, applicable TOPs
and applicable TPs to be complete and adequate. In addition, the
contribution of any or all of these entities may be needed to identify
suitable and valid corrective action options. The RAS-owner should be
the entity to choose the option to submit to its reviewing RC (R7).
Document Name:
0
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0
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Thomas Foltz - AEP - 5 -
Selected Answer:
Yes
Answer Comment:
AEP agrees with the application of R6 as the time frame for analysis,
which aligns with R1 in PRC‐004‐4.
Document Name:
0
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0
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Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
No
We agree with R6 to require the RAS-Owner to conduct the analysis
but suggest that the RC should be added to this requirement (or in a
new requirement) to review and concur with the analysis results (or
request modifications or additional information).
Document Name:
Answer Comment:
0
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0
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Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
Answer Comment:
ATC recommends that R6 (analyze RAS operations or misoperations)
should involve the affected TP, TOPs and RAS-owners. If the RASowner is selected to be the lead for these analyses, then consider
wording like, “Each RAS-owner, in conjunction with affected
Transmission Planners and Transmission Operators shall analyze . . .“
Affected TPs and TOPs have knowledge and capabilities to assess the
system impacts of a RAS in the planning horizon and operating horizon
that RAS-owners do not have. The analysis of the RAS and
identification performance deficiencies would need to include the
contribution of RAS-owners, applicable TOPs and applicable TPs to be
complete and adequate.
ATC recommends a “90-calendar day” time frame in R6, rather than
“120-calendar day” timeframe or state as “a timeframe mutually agreed
upon with its RC” is incorporated into the requirement.
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0
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0
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Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
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Answer Comment:
0
0
Dislikes:
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
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0
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Answer Comment:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
Requirements R5 and R7 pertain to the submittal of Corrective Action
Plans (CAPs) to the Reliability Coordinator (RC) for review, and
Requirement R8 mandates the implementation of each CAP. Question
8 addresses these requirements.
Document Name:
0
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0
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Jared Shakespeare - Peak Reliability - 1 -
Answer Comment:
Selected Answer:
No
Answer Comment:
If it’s a large RAS issue, the timeframe to evaluate should be shorter. In
addition, the timeframe to mitigate the issues should be more clearly
defined.
Document Name:
0
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0
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Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Requirements R5 and R7 pertain to the submittal of Corrective Action
Plans (CAPs) to the Reliability Coordinator (RC) for review, and
Requirement R8 mandates the implementation of each CAP. Question
8 addresses these requirements.
Document Name:
0
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0
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Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
No
Answer Comment:
Partial operation of an RAS is not listed and should be analyzed. In
addition, an RC needs to ability to require the RAS-entity to investigate
real time performance issues, such as an RAS that is unavailable on a
repetitive basis. In addition, there should be a requirement that that
status of the RAS is monitored. Language should be changed as
follows:
R6. Within 120‐calendar days of each RAS full or partial operation or
each failure of a RAS to operate or an an RAS issue is raised by the
RC, each RAS entity shall analyze the RAS for performance
deficiencies. The analysis shall determine whether the: [Violation Risk
Factor:] [Time Horizon:]
6.1. Power System conditions appropriately triggered the RAS.
6.2. RAS responded as designed.
6.3. RAS was effective in mitigating power System issues it was
designed to address.
6.4. RAS operation resulted in any unintended or adverse power
System response.
6.5 RAS Owner(s) shall monitor RAS status.
Requirements R5 and R7 pertain to the submittal of Corrective Action
Plans (CAPs) to the Reliability Coordinator (RC) for review, and
Requirement R8 mandates the implementation of each CAP. Question
8 addresses these requirements.
Document Name:
0
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0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
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0
Dislikes:
Gul Khan - Oncor Electric Delivery - 2 - TRE
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Please elaborate on the definition of an operation used in this
context. Are we discussing the relay just arming or are we discussing
the whole sequence of operations involved in the RAS?
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0
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0
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Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
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0
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0
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
ERCOT agrees that the RAS entity should evaluate RASs under the
circumstances identified in Requirements R5 and R6, but would
suggest that such entities be required to provide the results of such
assessments to their Reliability Coordinator and Planning Coordinator.
Likes:
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Answer Comment:
0
0
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
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0
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Answer Comment:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
No
RAS-entity should be responsible for R6 instead of RAS-owner. The
RAS-entity, being designated to represent all RAS-owners, is in the
best position to evaluate the operation of a RAS.
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0
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0
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
Likes:
0
Dislikes:
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
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Likes:
0
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
Yes
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Likes:
0
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Answer Comment:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
Yes
Similar to PRC-004-3 Protection System Misoperation Identification and
Correction, when a RAS operates or fails to operate it should be
reviewed. It is too simplistic to say each RAS-owner will analyze a
RAS operation, especially if the RAS implicates components owned by
different entities, like a TO, DP, GO, and where the appropriate entity to
review system response is the TP and PC. We also suggest moving
Parts 6.1 to 6.4 to either the Rationale for Requirement R6, or the
Technical Guidelines and out of the requirement.
Agree with R6 as far as it goes. However, the RAS owner may not be
in the position to evaluate Parts 6.3 and 6.4. The applicability of these
sub-Parts should include the RC.
Likes:
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Answer Comment:
0
0
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
While we agree that R6 is necessary and its application will certainly
identify performance deficiencies, we are concerned how an applicable
entity will provide compliance with “each failure of a RAS to
operate.” We urge the drafting team to avoid creating another “prove
the negative” requirement. Will the applicable entity have to retain 6second scan data for every hour of every year to demonstrate that no
conditions ever existed that would have triggered a RAS? This is not
reasonable and should be modified.
Document Name:
0
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0
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
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0
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0
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David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
No
Answer Comment:
It is more efficient for the RAS-entity to initially evaluate each RAS
operation, and then involve the RAS-owner(s) as appropriate. We
request a change to “Within 120‐calendar days of each RAS
operation or each failure of a RAS to operate, the RAS-entity shall
analyze the RAS for performance deficiencies. Each RAS‐owner
shall cooperate in this RAS-entity led analysis, as needed. …”
Document Name:
0
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0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
1)Hydro One Networks Inc. believes that the term “performance
deficiencies” and requirements R6.1-R6.4 seem to be more
related to design of the RAS. It is not clear if a misoperation of an
associated relay, DC system , AC circuitry, etc., are included in
this requirement. Note that the “new” definition of RAS states that
it is a ‘scheme’ and not a ‘protective system’ as is originally
defined in SPS which would include the relays, DC system, AC
sensing devices, etc.
2)
Hydro One Networks Inc. agrees with NPCC on the
following: We agree with R6 and its Parts; however, the RAS
owner will not be in the position to evaluate R6.3 and R6.4. The
applicability of these sub requirements should include the RC.
3)
Hydro One Networks. Inc. further agrees with NPCC on the
following: A requirement cannot be assigned to more than one
functional entity. Thus, this requirement should be structured
similar to PRC-004-3, where individual requirement for each step
of the sequence involved in evaluating operation and
misoperation.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
HQT agrees with the intent of R6. However, it seems like this
requirement is trying to cover two very different aspects related to RAS
operation: RAS equipment and system performance. The burden of the
whole evaluation is assigned to the RAS-owner, which is probably bestsuited to perform the evaluation of 6.2 RAS responded as designed, but
not 6.3 and 6.4 which are related to system response analysis. This
would probably be better addressed another entity (RC? TOP?). HQT
recommends splitting R6 in two distinct aspects: equipment
performance and System performance, and to assign the appropriate
entity for both.
R6.1 is redundant with R6.2. If the RAS responded as designed, then
Power System conditions appropriately triggered the RAS.
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0
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0
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Answer Comment:
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0
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0
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Answer Comment:
Texas RE is concerned that with a 60 month evaluation timeframe
specified in R4, there could be changes that affect the RAS that are not
evaluated until the 60 months or an operation of the RAS. A new
transmission line could be built where the RAS was not considered and
the RAS operates unnecessarily because of the new line.
Document Name:
0
Likes:
0
Dislikes:
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
1)Hydro One Networks Inc. believes that the term “performance
deficiencies” and requirements R6.1-R6.4 seem to be more
related to design of the RAS. It is not clear if a misoperation of an
associated relay, DC system , AC circuitry, etc., are included in
this requirement. Note that the “new” definition of RAS states that
it is a ‘scheme’ and not a ‘protective system’ as is originally
defined in SPS which would include the relays, DC system, AC
sensing devices, etc.
2)
Hydro One Networks Inc. agrees with NPCC on the
following: We agree with R6 and its Parts; however, the RAS
owner will not be in the position to evaluate R6.3 and R6.4. The
applicability of these sub requirements should include the RC.
3)
Hydro One Networks. Inc. further agrees with NPCC on the
following: A requirement cannot be assigned to more than one
functional entity. Thus, this requirement should be structured
similar to PRC-004-3, where individual requirement for each step
of the sequence involved in evaluating operation and
misoperation.
Document Name:
0
Likes:
0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirements R5 and R7 pertain to the submittal of Corrective Action
Plans (CAPs) to the Reliability Coordinator (RC) for review, and
Requirement R8 mandates the implementation of each CAP. Question
8 addresses these requirements.
0
Likes:
0
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
Answer Comment:
Document Name:
0
Likes:
0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Requirements R5 and R7 pertain to the submittal of Corrective Action
Plans (CAPs) to the Reliability Coordinator (RC) for review, and
Requirement R8 mandates the implementation of each CAP. Question
8 addresses these requirements.
Document Name:
0
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0
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Answer Comment:
Selected Answer:
No
Answer Comment:
R6 will address after-the-fact performance deficiencies.
R4 will determine if a scheme is still needed and effective. For new
schemes, they will be designed correctly, but if a "grandfathered"
scheme is still needed and effective per the TP studies, a flawed design
in implementing the scheme could be easily overlooked since the
design aspect of a scheme may not be part of a TP review.
Making updating Attachment 1 part of R4 a requirement could address
this.
Document Name:
0
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0
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
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8.
Corrective Action Plans (Requirements R5, R7, and R8): Do you agree that the application of
Requirements R5, R7, and R8 would address the reliability objectives associated with CAPs? If no, please
provide the basis for your disagreement and describe an alternate proposal.
Selected Answer:
No
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Answer Comment:
The inclusion of both RAS-entities and RAS-owners in this draft
standard is problematic. We suggest that the standard is simpler and
more effective if the Applicability is limited to a single equipment-owning
entity. This single RAS entity should be the equipment-owning entity
having the wide-area perspective of the BES, which is normally the
Transmission Owner. R5, R6, R7, and R8 will likely be ineffective and
unnecessarily complicated when there are multiple RAS-owners. The
RAS-entity described above should be assigned the responsibility to
submit an overarching Corrective Action Plan (R5 and R7), to analyze
RAS operations (R6), and to implement the CAP (R8) based on its
discussion and cooperation with the multiple RAS-owners.
Document Name:
0
Likes:
0
Dislikes:
John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Answer Comment:
While we agree that application of the requirements would address
reliability objectives, we have a few concerns:
• Both R5 and R7 relate to RAS’s that are in service, and in both
cases deficiencies have been found. We believe 6 months is too long
to submit a CAP to the RC. There has already been a significant
amount of time since the RAS was found deficient and 3 months should
be adequate time to develop a CAP. This is a critical function and there
is risk to having it operational when it is known to have deficiencies.
• Nowhere does the RC need to review the CAP in a specified
timeframe and agree that it solves the problem(s) identified, and issue a
formal statement to that effect. There should be requirement for that
step. A RAS owner would be unwilling to implement a CAP unless the
RC agreed that it is adequate.
• Requirement 7 should be revised to say: “. . .each RAS-Owner
shall submit a Corrective Action Plan for review and approval by its
reviewing Reliability Coordinator(s).”
To assure that the CAPs submitted per R5 and R7 are suitable and
valid CAPs to address the associated reliability objectives, the CAP
must be chosen from CAP options that any or all of the applicable RASowners, applicable TOPs, and applicable TPs have determined are
suitable and valid CAP options. The identification of suitable and valid
CAP options should be included in R4 and R6.
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
We generally agree with the application of R5, R7 and R8 would
address the reliability objectives associated with CAPs, but R8 should
be revised to provide a time frame for completing the implementation as
otherwise, a CAP’s implementation can be deferred indefinitely.
Document Name:
0
Likes:
0
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Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
Answer Comment:
ATC proposes that R5 require TPs to identify suitable and valid CAP
options to address any identified deficiencies in R4 and provide these
options to the applicable RAS-owners. ATC also proposes adding a
requirement (or expand R5) to require RAS-owners to choose one of
the viable options and submit their choice to their reviewing RC for
approval. Also, ATC proposes adding a new requirement (or expanding
R5) to require each RC to accept or reject any CAPs that are submitted
by RAS-owners.
ATC suggests a “90-calendar days” time frame, rather than “six full
calendar months” timeframe or rewording such as “or a timeframe
mutually agreed upon with its RC” is incorporated into R5. A quicker
resolution of any deficiency would be better and only allow more time
when it is really needed.
ATC suggests that R7 (and any new requirements) be revised similar to
the proposals related to R5. Require TPs be required to identify suitable
and valid CAP options to address any identified deficiencies in R6 and
provide these options to the applicable RAS-owners. Require RASowners to choose one of the viable options and submit their choice to
their reviewing RC for approval. Require each RC to accept or reject
any CAPs that are submitted by RAS-owners.
Document Name:
0
Likes:
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
Requirement R9 mandates each RAS-owner periodically perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non-Protection System components. Question 9
pertains to Requirement R9.
Document Name:
Answer Comment:
0
Likes:
0
Dislikes:
Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
No
R8 should include language that the CAPs must be approved by the RC
and not merely submitted.
Document Name:
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0
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Answer Comment:
0
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirement R9 mandates each RAS-owner periodically perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non-Protection System components. Question 9
pertains to Requirement R9.
Likes:
0
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Document Name:
Answer Comment:
0
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
No
Answer Comment:
We generally agree with the application to address reliability but an R5
and R7 CAP submittal should be made by the RAS entity, it should not
be submitted to the RC by multiple RAS Owners.
R5. Within six full calendar months of being notified of a deficiency in its
RAS based on the evaluation performed pursuant to Requirement R4,
the RAS-entity shall submit a Corrective Action Plan to its reviewing
Reliability Coordinator(s). [Violation Risk Factor:] [Time Horizon:]
R7. Within six full calendar months of identifying a performance
deficiency in its RAS based on the analysis performed pursuant to
Requirement R6, the RAS-entity shall submit a Corrective Action Plan
to its reviewing Reliability Coordinator(s). [Violation Risk Factor:] [Time
Horizon:]
Requirement R8 should include a timeframe for implementing the CAP.
R8. For each CAP submitted pursuant to Requirement R5 and
Requirement R7, each RAS owner shall implement the CAP within 90
days unless an alternative alternate schedule is approved by the
RC. [Violation Risk Factor:] [Time Horizon:]
Requirement R9 mandates each RAS-owner periodically perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non-Protection System components. Question 9
pertains to Requirement R9.
Document Name:
0
Likes:
0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
Document Name:
0
Likes:
0
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Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
However, for consistency, I believe that the 120 days in requirement R6
should be changed to 4 months instead of 120 calendar days to be
consistent with the other dates in the standard. Although it is much
easier to keep track of the days.
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Answer Comment:
0
0
Dislikes:
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
ERCOT supports the comments of the SRC for these requirements.
Document Name:
0
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0
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
No
Answer Comment:
R5 and R7 should specify a CAP is created only if deficiency is on the
RAS-owners part of the RAS. As written, all RAS-owners would be
responsible for submitting CAPs if a single deficiency was identified on
just one part of the RAS. As written, a RAS-owner would be
responsible for writing a CAP (R5 or R7) and implementing the CAP
(R8) for something they may have no control over, if the deficiency is on
another RAS-owners part of the RAS.
Document Name:
0
Likes:
0
Dislikes:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
No
While we agree with the development of the CAP meeting the intent of
R5,R7, and R8, the plan should be provided to the collaborative forum,
on which the RC and PC participate.
0
Likes:
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Document Name:
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
No
See previous comment on the RC’s being inappropriate first line
evaluators of RASs.
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Document Name:
Answer Comment:
Selected Answer:
No
In addition to the “six full calendar month(s)” submission periods,
periods for acceptable implementation of the CAP should be
specified. A statement should be included in requirement R5 to
address the situation when a RAS-owner disagrees with the
Transmission Planner’s evaluation of a RAS.
Requirement R7 should be changed from “submit Corrective Action
Plan to its reviewing Reliability Coordinator(s)” to “RAS-entity provide
notice to the affected RC and TOP of the deficiency and when the
deficiency is planned to be corrected”. This is good practice to keep
operators aware of a change in RAS performance.
A requirement should be added to notify the RC and TOP when the
RAS is performing correctly after the CAP has been completed.
0
Likes:
0
Dislikes:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Document Name:
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
While we have no issue with documenting and developing a CAP, we
do not understand the need to submit a CAP to an RC. The RC is not
the equipment owner and may not understand the details of the
CAP. What purpose is served by submitted the CAP? Any purpose
such as notifying the RC of the dates when the RAS will be repaired or
how contingencies should be modified in real-time contingency analysis
to reflect the deficient operation of the RAS can be handled via other
means. The responsible entity that develops the CAP should maintain
and update the plan, which would be available for auditors to review.
We also are concerned that R8 could prevent a CAP from being
modified. If the applicable entity must implement the CAP, that implies
the moment a CAP is finalized that the measure of compliance
begins. Thus, if an applicable entity adds a one month delay to a CAP
due to the inability to schedule the work or get parts, they would be in
technical violation of the requirement. The standards drafting team
modifying PRC-004 has already addressed this issue. We suggest this
drafting team adopt their approach which is used in PRC-004-4 R6.
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Exelon thinks there should be an attempt to specifiy a "time not to
exceed" for implementing the corrective action following an RAS
performance issue. We understand that the mitigation could cover a
wide range of issues but putting no limit on the mitigation seems
problematic.
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0
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David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Answer Comment:
Answer Comment:
Yes
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0
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0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc. believes that the standard should:
(R5 and R7) Clearly specify that CAP shall include
work (corrective actions) and the work schedule (target
completion date). This is written in the rationale for R8, but is not
specified in the body of the standard.
Requirements are not clear on what to do in case a CAP
changes. Does the RAS-entity need to resubmit changes in
CAP (work or work schedule)?
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
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Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
A schedule for implementation should be part of R8 (or R5 and R7).
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0
0
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
No
Answer Comment:
R5 has the incorrect functional entity identified. Manitoba Hydro believe
that in most cases, the Transmission Planner identifies the need for the
RAS as part of the TPL assessments or other technical studies. If the
TP performs a five year assessment and finds the RAS does not work
as originally intended, we believe the TP is in the best position to
develop a corrective action plan. Such a plan might be to change logic
or possibly require faster operation speed. This plan would be tested
and functional specifications developed and given to the RAS owner.
The RAS Owner would determine the construction schedule, feasibility
and cost of the required changes. The TP would then decide whether
the RAS should be retained and modified or another change
implemented. The TP should be submitting the Corrective Action Plan
to the RC in R5 and not the RAS Owner. The RAS-Owner will submit
the functional modification changes to the RC as part of R1, if the RAS
is to be changed.
It seems unnecessary to include Requirement R8 in the standard.
Requirement R5 and R7 already identify the need for the CAP and the
RC is informed. The RC is in the best position to identify possible
actions in real time (system readjustments) if the CAP is not
implemented in a timely manner. TPL-001-4 will catch any
contingencies (P1-P7) that do not meet the performance requirements
in Table 1. This requirement appears to be redundant and will only
serve to penalize an entity multiple times for the same issue.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Answer Comment:
Texas RE recommends a requirement for reviewing and approving a
Corrective Action Plan. If the RC does not review the CAP, the CAP
might not be sufficient and could create a reliability gap.
Texas RE is concerned that the timeframes in this standard are too
lengthy:
• A 60 month evaluation of RAS per R4;
• A CAP submitteal within six full calendar months of being notified
of a deficiency in RAS per R5;
• An analysis of RAS within 120 calendar days per R6;
• CAP submittal within six full calendar months per R7; and
• No time limit on implementing the CAP per R8 so a performance
deficiency affecting reliability could go uncorrected for years and
entities would remain compliant.
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0
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0
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc. believes that the standard should:
(R5 and R7) Clearly specify that CAP shall include
work (corrective actions) and the work schedule (target
completion date). This is written in the rationale for R8, but is not
specified in the body of the standard.
Requirements are not clear on what to do in case
a CAP changes. Does the RAS-entity need to resubmit changes
in CAP (work or work schedule)?
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0
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0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirement R9 mandates each RAS-owner periodically perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non-Protection System components. Question 9
pertains to Requirement R9.
0
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0
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
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Answer Comment:
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0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
We generally agree with the application of R5, R7 and R8 would
address the reliability objectives associated with CAPs, but R8
should be revised to provide a time frame for completing the
implementation as otherwise, a CAP’s implementation can be
deferred indefinitely.
Requirement R9 mandates each RAS-owner periodically perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non-Protection System components. Question 9
pertains to Requirement R9.
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
Under Requirement R5, it seems like the CAP should also be submitted
to the Transmission Planner because they identified the issue in the
first place.
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Answer Comment:
0
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0
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
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0
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0
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Answer Comment:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
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0
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0
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Answer Comment:
Answer Comment:
Yes
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0
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0
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9.
Functional Testing of RAS (Requirement R9): Do you agree that functional testing of each RAS would
verify the overall RAS performance and the proper operation of non-Protection System components? If
no, please provide the basis for your disagreement and describe an alternate proposal.
No
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
As above, the RAS-entity with overall BES system view should be
responsible to perform testing of the RAS, based on input from the
other RAS-owners.
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0
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0
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Answer Comment:
Document Name:
Yes
0
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0
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
The six calendar years interval is not compatible with the intervals
associated with the different kinds of components that may be in a
RAS. Consider wording like, “replace “proper operation of nonProtection System components” proper operation of components that
do not perform a System Protection function. Capacitor bank switching
control, transformer tap changer control, phase shifter control, and
generation runback control. Is there already a specific requirement in
PRC-005-2 that covers the non-Protection System components of a
RAS (PLCs may be used in a RAS, but these are not specifically
covered in PRC-005-2). We propose that R9 be removed from PRC012-2 and moved to PRC-005 (or a new PRC Standard that addresses
non protective components) standard, so all the maintenance and
testing requirements are consolidated in one place, rather than having a
few outliers.
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0
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0
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Thomas Foltz - AEP - 5 -
Selected Answer:
No
Answer Comment:
AEP does not believe that R9 should be included in PRC-012-2.
If anywhere, it should instead be included in PRC-005. A similar
requirement exists within the SPR maintenance obligations of
PRC-005-4, which requires non-electrical components to be
maintained every 72 months. If there are special testing
requirements for non-protection system components associated
with RAS, then they should be included in PRC-005 where all the
other maintenance and testing is identified
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0
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Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
Answer Comment:
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0
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0
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
Functional testing of RAS is a maintenance activity that would be better
included in the PRC-005 standard. The present PRC-005-2 Reliability
Standard is the maintenance standard that replaces PRC-005-1, 008,
011 and 017 and was designed to cover the maintenance of
SPSs/RASs. However, Reliability Standard PRC-005-2 lacks intervals
and activities related to non-protective devices such as programmable
logic controllers. ATC recommends that a requirement for maintenance
and testing of non-protective RAS components be added to a revision
of PRC-005-2, rather than be an outlying maintenance requirement
located in the PRC-012-2 Standard.
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0
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Answer Comment:
0
Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
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0
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0
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Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
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0
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0
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
Answer Comment:
Answer Comment:
Requirements R10 and R11 pertain to the RAS database, Attachment
3, and the sharing of RAS information for reliability-related needs.
Questions 10 11, 12, and 13 pertain to these topics.
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0
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0
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Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
Yes
Answer Comment:
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0
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0
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirements R10 and R11 pertain to the RAS database, Attachment
3, and the sharing of RAS information for reliability-related needs.
Questions 10 11, 12, and 13 pertain to these topics.
0
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0
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Answer Comment:
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Yes
Requirements R10 and R11 pertain to the RAS database, Attachment
3, and the sharing of RAS information for reliability-related needs.
Questions 10 11, 12, and 13 pertain to these topics.
0
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0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
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Answer Comment:
Selected Answer:
Yes
We would like the SDT to discuss the possibility of using either actual
operation of the RAS that was found to be functionally correct or
perhaps maintenance testing of the RAS to reset the six-year testing
requirement.
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0
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0
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Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
No
Answer Comment:
Answer Comment:
Although functional testing would verify that the scheme is working as
designed, there is no reason to believe that an RAS is any different
from another protection system i.e., it would need to be tested at
intervals outside the normal maintenance program. The testing of RAS
should fall in line with PRC-005-3 requirements for monitored systems
and unmonitored systems.
By requiring “at least once every six calendar years, each RAS‐owner
shall perform a functional test,” the drafting team is forcing all owners of
a RAS that has any Protection Systems in it to abandon the PRC-005-3
12 year Maximum Maintenance Intervals allowed in tables 1-1, 1-2, 1-3,
1-5, and 4.
If Requirement R9 is adopted as stated in this draft of the standard,
each segment of a RAS would have to be tested at a maximum interval
of 6 calendar years. This would require, for example, that voltage and
current sensing devices providing inputs to protective relays of a RAS
“shall” be tested “at least once every six calendar years” instead of 12
Calendar years allowed in Table 1-3 of PRC-005-3.
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0
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Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
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0
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0
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
ERCOT agrees with the need to test the functionality of RASs;
however, it recommends that such testing be coordinated with the RC
and that the RC be provided with the results of such testing and any
associated corrective actions or modifications that are determined by
the RAS entity to be necessary following such testing.
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0
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0
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Duke Energy requests further explanation on the benefit of
performing “functional testing” as opposed to what is tested
currently in PRC-005 and what exactly will be required to be
performed outside of what is already performed via the required
PRC-005 functional testing. It appears that there may be some
redundancies in testing between PRC-012-2 and PRC-005.
Also, R9 adds additional maintenance activities for a RAS beyond
the PRC-005-3 requirements. PRC-012 requires that an entity verify
the proper operation of the non‐Protection System (control)
components of a RAS that are not addressed in PRC‐005. It will
also require that an entity verify the overall RAS performance. This
would be difficult to plan and coordinate, and in some cases
would cause intentional and significant system perturbation as
well as potential loss of customer load.
Lastly, as written, the supplement sounds like an entity is
expected to simulate an out-of-step/power swing condition, and
test the internal logic of the SEL relays, which is beyond anything
that currently performed for PRC-005. Is this interpretation
accurate? If this is accurate, Duke Energy disagrees with the
inclusion of such maintenance activities in a separate standard,
and believes that all maintenance activities should be kept in one
document (PRC-005).
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0
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0
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Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Yes
Answer Comment:
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0
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0
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Yes
0
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0
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
No
There needs to be additional definition on what constitutes a functional
test. It is not clear what it mean by “non-Protection System
components”. We would not want to trip generators or load as part of
this.
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0
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Answer Comment:
0
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
No
This would be difficult and in some cases would cause intentional and
significant system perturbation as well as potential loss of customer
load.
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
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Answer Comment:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
Yes
We agree with the segmented testing approach. A Technical Guideline
may be required to explain how the six year cycle is measured when
allowing segmented testing. Segmented testing can test all
components of an RAS every six years, but an individual component
could end up being tested once every 10 years; for example, tested in
year 1 and year 10.
0
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0
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Document Name:
Answer Comment:
Selected Answer:
Yes
In order to better align with the Rationale provide for R9, Tri-State
suggests the following changes to the Requirement and the associated
Measure:
Requirement 9: Each RAS-owner shall perform a functional test of
each individual segment of each RAS at least once every six calendar
years per segment, or at least once every six calendar years shall
perform a functional test of each RAS, to verify the overall RAS
performance and the proper operation of non‐Protection System
components. A correct operation of the RAS would qualify as a
functional test.”
Measure 9: “Acceptable evidence may include, but is not limited to,
date‐stamped documentation of the functional testing of the entire RAS,
or of the individual segments of the RAS. Alternatively, acceptable
evidence may also include date stamped documentation of a correct
operation of the entire RAS or of the individual segments of the RAS.”
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Answer Comment:
0
0
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
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0
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0
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Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
We are concerned that this requirement will create redundancies with
PRC-005. As an example, PRC-005 already requires the applicable
entity to verify the output of protection relays that are part of RAS in
Table 1-1 and to verify all paths of control circuits in Table 3 every 12
calendar years. Furthermore, the periodicity associated with R9 is not
consistent with the tests required in PRC-005. If R9 persists, these
redundancies should be removed from PRC-005.
0
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0
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Answer Comment:
Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
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0
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David Jendras - Ameren - Ameren Services - 3 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
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0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
1) Hydro One Networks Inc. agrees with NPCC with the following: any
maintenance activities associated with RAS should not appear in this
standard. The functional testing approach attempted in this standard is
found to be unworkable and confusing. The only alternative proposal
is to have all maintenance activities associated with RAS in a future
revision of PRC‐005.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
HQT understands the intent of R9, but having testing and maintenance
of RAS covered in two separate standards (PRC-005-3 and PRC-0122) is confusing and unpractical. NERC should seriously consider
covering the testing and maintenance of every component of a RAS
within the same standard.
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0
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0
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
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0
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0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Texas RE does not agree that RAS is not a protection system
component. Texas RE recommends that there is a requirement to test
RAS components. Texas RE is concerned that the verbiage “each
RAS” will not require entities to functionally test all RAS interactions.
0
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0
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Document Name:
Answer Comment:
Selected Answer:
No
1) Hydro One Networks Inc. agrees with NPCC with the
following: any maintenance activities associated with RAS should
not appear in this standard. The functional testing approach
attempted in this standard is found to be unworkable and
confusing. The only alternative proposal is to have all
maintenance activities associated with RAS in a future revision of
PRC-005.
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0
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0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Requirements R10 and R11 pertain to the RAS database, Attachment
3, and the sharing of RAS information for reliability-related needs.
Questions 10 11, 12, and 13 pertain to these topics.
0
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0
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
Answer Comment:
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0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Requirements R10 and R11 pertain to the RAS database, Attachment
3, and the sharing of RAS information for reliability-related needs.
Questions 10 11, 12, and 13 pertain to these topics
Document Name:
Answer Comment:
0
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0
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
It is recommended that RAS maintenance/testing be consolidated into
only one standard, either PRC-005 or PRC-012, not both.
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0
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Answer Comment:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
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0
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0
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Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
However, the extent of monitoring of the non-protection systems should
be considered in allowing for exeptions/extensions.
For example, if a PLC is continuously monitored, the 'health' of the PLC
should not be of any concern and a functional test of the PLC should
not be required. What could be required though is a functional test of
the logic within the PLC. They may not be mutually exclusive in most
cases, but it should be considered and left up to the RAS entity to
decide.
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0
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0
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Yes
Answer Comment:
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0
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0
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10.
Choice of Reliability Coordinator (Requirement R10): Do you agree with the Reliability Coordinator
being the functional entity designated to maintain the RAS database? If no, please provide the basis for
your disagreement, your choice of functional entity, and the rationale for your choice.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
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0
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0
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Answer Comment:
Document Name:
Yes
0
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0
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
No
We agree that the RC may be the best single functional entity to assign
the obligation of maintaining a RAS database. However, we suggest
that R10 include the obligation to provide information from this
database to functional entities that request it and have reliability need
for it (e.g. PCs and TPs). Consider wording like, ”. . . provide
information from the database to functional entities that request and
have a reliability need for the RAS information”.
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Answer Comment:
0
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0
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Thomas Foltz - AEP - 5 -
Selected Answer:
Yes
Answer Comment:
AEP seeks clarification on line item #3 to ensure the existing evaluation
performed by the RRO, in accordance with industry best practice, is
the most recent date supporting requirement R2 of this standard.
3. Expected or actual in‐service date; most recent (Requirement R2)
review date; 5‐year (Requirement R4) evaluation date; and, date of
retirement, if applicable
Document Name:
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0
0
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Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
While we agree that the RC is the appropriate entity to maintain the
database, pursuant to our comment under Q3 in which we suggest the
SDST to consider involving Planning Coordinators in the evaluation
process, we suggest the PC also be assigned this task for RASs that
have been planned and evaluated in the long-term planning timeframe.
Some entities may have a need for planned RAS information for
modeling.
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0
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Answer Comment:
0
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
No
ATC agrees that the RC may be the best single functional entity to
assign the obligation of maintaining a RAS database. However, ATC
suggests that R10 include the obligation to provide information from this
database to functional entities that request it and have a reliability need
for it (e.g. PCs and TPs). Consider rewording such as,” . . . provide
information from the database to functional entities that request and
have a reliability need for the RAS information”.
0
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0
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Answer Comment:
Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
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0
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0
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Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
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0
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Answer Comment:
Document Name:
Yes
0
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0
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Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
Yes
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0
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0
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Answer Comment:
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
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0
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Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
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0
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0
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
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0
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0
Dislikes:
Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
While ERCOT agrees that the RC is the appropriate entity to maintain
the database, pursuant to its comment under Q3 in which it is
suggested that the SDST consider involving Planning Coordinators in
the evaluation process, ERCOT suggests the RC be responsible for
providing the database to the PC.
Document Name:
0
Likes:
0
Dislikes:
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Duke Energy questions whether requiring the RC to maintain the
RAS database enhances reliability. This requirement can be
viewed as an administrative burden on the RC, and we feel that
instead of requiring the RC to maintain a database, that the RC
should only be required to be familiar with the RAS that exists in
its area.
Document Name:
0
Likes:
0
Dislikes:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
No
The RCs should not be responsible for the evaluation and coordination
of RASs therefore making them in charge of the database of RASs
would be inappropriate. The RCs should be notified of RAS
installations, modifications and retirements and could have a
requirement to acknowledge receipt from the RAS owners on any of the
above RAS activities.
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Document Name:
Answer Comment:
Selected Answer:
Yes
Answer Comment:
This could be the RC or PC; both have a need to know the location and
performance characteristics.
Document Name:
0
Likes:
0
Dislikes:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
We question the need to have a requirement to maintain a database
especially since many of the other requirements cannot be met without
information in the database. In essence, the other requirements create
an indirect requirement for a database. However, we believe it is
actually the PC that should maintain this information if the requirement
persists.
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
David Jendras - Ameren - Ameren Services - 3 -
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
Answer Comment:
See Q1 above.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Texas RE recommends aligning Attachment 1 with Attachment 3. The
rationale for R10 states that the database will be comprehensive but it
isn’t comprehensive without the information in both Attachment 1 and
Attachment 3.
Document Name:
0
Likes:
0
Dislikes:
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
See Q1 above.
Document Name:
0
Likes:
0
Dislikes:
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
No
This is an administrative requirement that seems inappropriate for RC
entities.
Document Name:
Answer Comment:
0
Likes:
0
Dislikes:
Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
While we agree that the RC is the appropriate entity to maintain
the database, pursuant to our comment under Q3 in which we
suggest the SDST to consider involving Planning Coordinators in
the evaluation process, we suggest the PC also be assigned this
task for RASs that have been planned and evaluated in the longterm planning timeframe. Some entities may have a need for
planned RAS information for modeling.
Note - These SRC comments represent a consensus of the
ISOs/RTOs with the exception of ERCOT.
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer Comment:
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Yes
A method for Regional Entities to transfer information from their existing
SPS/RAS databases to the appropriate RC(s) should be considered.
Likes:
0
Dislikes:
Document Name:
Answer Comment:
0
11.
Information listed in Attachment 3 (Requirement R10): Do you agree that the RAS information
required in Attachment 3 provides the Reliability Coordinator with enough detail of each RAS to meet its
reliability-related needs? If no, please identify what other reliability-related information should be included
in Attachment 3 and the rationale for your choice.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Selected Answer:
Answer Comment:
Thomas Foltz - AEP - 5 -
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
Document Name:
Likes:
Answer Comment:
0
0
Dislikes:
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
No
Comments: PacifiCorp represents that it is unable to answer this
question without the RC providing more detail about its reliability-related
needs.
Document Name:
Likes:
Answer Comment:
0
0
Dislikes:
Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
No
Attachment 3 should also include other information required by the RC
Data Request to allow for information beyond that currently specified in
Attachment 3.
0
Likes:
0
Dislikes:
Document Name:
Answer Comment:
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Add RC approval date
Document Name:
0
Likes:
0
Dislikes:
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Answer Comment:
Selected Answer:
No
Answer Comment:
Attachment 3 should include a listing of the RAS Owners.
Document Name:
0
Likes:
0
Dislikes:
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
See Duke Energy’s response and comment to question 10.
Document Name:
0
Likes:
0
Dislikes:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Yes
R10 should include a sub-requirement for RCs to share their database
with neighboring RCs to provide coordination of RAS schemes near RC
borders.
Likes:
Document Name:
Answer Comment:
0
0
Dislikes:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Answer Comment:
Selected Answer:
No
Besides the initiating condition(s), there should be a sequence of
events (actions taken) by the RAS for each condition.
Document Name:
0
Likes:
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Answer Comment:
In addition to the detail in attachment 3, it would be important to receive
breaker diagrams, list of elements being monitored and actual trigger
levels, any associated pre-RAS action alarms, elements being triggered
by the RAS (i.e. Breaker at substations, etc).
Document Name:
1
Likes:
Florida Municipal Power Agency, 3,4,5,6, Gowder Chris
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The wording of the lengths of time for meeting a requirement should be
consistent. Requirement R4 specifies 60 full calendar months,
Attachment 3 Item 3 refers to a 5-year evaluation date.
Document Name:
0
Likes:
0
Dislikes:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Chris Scanlon - Exelon - 1 -
Answer Comment:
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Answer Comment:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
Answer Comment:
Document Name:
Likes:
1
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Answer Comment:
Answer Comment:
Texas RE recommends aligning Attachment 1 with Attachment 3. The
rationale for R10 states that the database will be comprehensive but the
data is not comprehensive without the information in both Attachment 1
and Attachment 3.
Document Name:
0
Likes:
0
Dislikes:
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
0
Dislikes:
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Yes
Although the answer is Yes, it is made in the context of this is
information that should be provided as a matter of course to the RC as
an area operating entity and NOT because it should be keeping a
database or performing a review.
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Answer Comment:
Answer Comment:
Yes
Document Name:
0
Likes:
0
Dislikes:
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
No
The expectation should be that "grandfathered" schemes which may
never have been presented then be presented to the RC. This will
ensure that all schemes (new and existing) adhere to the new
requirements and guidelines.
That said, an agreed upon action plan to update the "grandfathered"
schemes per the new requirement should be acceptable.
0
Likes:
0
Dislikes:
Document Name:
Answer Comment:
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Answer Comment:
TVA supports the comment filed by the SERC Dynamics Review
Subcommittee (DRS) on this question.
Document Name:
0
Likes:
0
Dislikes:
12.
Requirement R11: Is there a reliability benefit of Requirement R11? Please provide the rationale for
your answer.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Yes
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Fulfillment of R11 would always provide a reliability benefit because the
requirement specified that the requesting entity has to have a reliabilityrelated need for the information.
Document Name:
0
Likes:
0
Dislikes:
Thomas Foltz - AEP - 5 -
Selected Answer:
Yes
Answer Comment:
AEP supports the applicability of R11, however we seek clarification on
the requirement to ensure that R11 applies only to RASs that are in‐
service.
Document Name:
0
Likes:
0
Dislikes:
Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
And please see our comment under Q10 for data that may be required
for modeling in the long-term planning timeframe.
Likes:
0
Dislikes:
Document Name:
Answer Comment:
0
Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Brian Bartos - CPS Energy - 3 -
Answer Comment:
Selected Answer:
No
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
Document Name:
Likes:
0
Dislikes:
Answer Comment:
0
Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
Answer Comment:
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Answer Comment:
Yes
Document Name:
Answer Comment:
0
Likes:
0
Dislikes:
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
No
The requirement is duplicative of other information sharing
requirements such as TOP-003-3 R5.
Document Name:
Likes:
Answer Comment:
0
0
Dislikes:
Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Answer Comment:
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
However, given the coordination that ERCOT recommends between the
RC and PC, it suggests that the provision of data between these
entities not be required to be governed on a “request” basis.
Document Name:
0
Likes:
0
Dislikes:
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Answer Comment:
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
Answer Comment:
But we believe the Measure and the RSAW should be written such that
the RAS-entity is not trying to prove the negative (that they received no
request). An attestation of “no requests received” should be sufficient
evidence.
Document Name:
0
Likes:
0
Dislikes:
Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
Yes
0
Likes:
0
Dislikes:
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
Yes
Is a request to provide information for the database described in R10
supposed to start the 30-day clock indicated in requirement R11? If so,
that should be made clear.
Document Name:
Likes:
Answer Comment:
0
0
Dislikes:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
No
While this requirement benefits the entity requesting the information,
R11 does not provide a clear system reliability benefit.
0
Likes:
0
Dislikes:
Document Name:
Answer Comment:
Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
0
Dislikes:
Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
No
Requirement R11 is a “in case we forgot an entity that needs the
information” requirement. It meets multiple paragraph 81 criteria (B1Administrative, B4 Reporting, and B7-Redundant). First, it is
administrative in nature and creates needless burden on the applicable
entity. Who makes the final judgment call on whether a reliability need
was demonstrated? The applicable entity? The requester? The
auditor? Because of this uncertainty, the applicable entity will spend
unnecessary time and resources on demonstrating compliance with a
requirement that has questionable reliability benefit. The questionable
reliability benefit is even demonstrated by the language of in the
supplemental materials on page 21 which begins with “Other registered
entities may (emphasis added) have reliability-related need.” These
materials do not even seem to be sure that there is reliability benefit
with the “may” language. Second, it requires reporting information to
third parties which appears to provide little reliability benefit. If this
requirement does not exist, entities that have the reliability related need
for this information still have multiple avenues to get the date (e.g.
regional model building processes, via Planning Coordinator, and via a
direct request). We simply do not believe an applicable entity will
refuse this information to a third party that is a reliability entity and truly
has the need for such data. Finally, this requirement is redundant with
other requirements in this standard that already require communication
of this information to other reliability entities such as the Reliability
Coordinator. Please remove this requirement before the first formal
posting.
Document Name:
Answer Comment:
0
Likes:
0
Dislikes:
Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Yes
Document Name:
0
Likes:
0
Dislikes:
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Answer Comment:
Selected Answer:
No
Answer Comment:
1)Hydro One Networks Inc.:
Regions and RCs will establish (have established) their own procedures
and requirements for exchange of detailed RAS data/model. The
requirement for providing general RAS data/model could be handled
by the MOD‐032 standard.
2)Hydro One Networks Inc. also agrees with NPCC in that: R11
mandates 30 calendar days for providing requested information
for a modelling need--is this intended to apply to Requirement
R10 as well for providing information to maintain the
database? If so, words must be added.
Document Name:
1
Likes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Dislikes:
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
The information provided through R10 is appropriate for a high level
view of RAS in a specific area, but is definitely not sufficient if an entity
has a reliability need for more information. In that sense, R11 seems
justified.
Document Name:
0
Likes:
0
Dislikes:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
No
Answer Comment:
Answer Comment:
It is not clear at what stage other entities might be involved in the RAS
assessment process and require models? Should the RC be
responsible for determining whether other entities have a reliability
related need for a proposed RAS model rather than the RAS owner?
Would it not be simpler to make this a requirement for the RAS owner
to develop a model for all RAS that are required to meet the
performance requirements of contingencies P1-P7 in Table 1 of TPL001-4 and include the model in the NERC model building process
(MOD-032-1) or possibly adjacent TPs and PCs can coordinate in
developing models through TPL-001-4 (R3.4.1 & R4.4.1)? Better yet,
the RAS owner should develop and provide the final tested model to its
Transmission Planner and Reliability Coordinator. The TP and RC
could share models with adjacent entities as required for reliability
purposes.
Document Name:
0
Likes:
0
Dislikes:
Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
Yes
Answer Comment:
Texas RE agrees that there is a benefit in sharing information that
affects operation of the grid. Texas RE recommends clarifying the term
“Reliability-related need”.
Document Name:
0
Likes:
0
Dislikes:
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
1)Hydro One Networks Inc.:
Regions and RCs will establish (have established) their own procedures
and requirements for exchange of detailed RAS data/model. The
requirement for providing general RAS data/model could be handled
by the MOD‐032 standard.
2)Hydro One Networks Inc. also agrees with NPCC in that: R11
mandates 30 calendar days for providing requested information for a
modelling need‐‐is this intended to apply to Requirement R10 as well
for providing information to maintain the database? If so, words must
be added.
Document Name:
0
Likes:
0
Dislikes:
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Document Name:
0
Likes:
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
And please see our comment under Q10 for data that may be
required for modeling in the long-term planning timeframe.
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0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
No
This requirement seems to assume that RAS-entities need to be
mandated to provide the requested information. Is there evidence that
RAS-entities will generally avoid providing the requested
information? If not, then this requirement imposes an administrative
burden with little reliability benefit.
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Document Name:
Answer Comment:
Selected Answer:
Yes
BPA requests additional clarification of “registered entity” as referenced
in R11. This is not a NERC-defined term.
“Within 30 calendar days of receiving a written request from a
registered entity with a
reliability‐related need to model RAS operation, each RAS‐entity shall
provide the
requesting entity with either the requested information or a written
response specifying the basis for denying the request.”
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Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
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Answer Comment:
Selected Answer:
No
Assuming the RC Database is up to date, the info in Attachment 3
already provides the same info requested per R11
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Answer Comment:
Answer Comment:
Yes
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13.
Choice of RAS-entity (Requirement R11): Do you agree with the RAS-entity being the entity
designated to provide the detailed RAS information to other registered entities with a reliability-related
need? If no, please provide the basis for your disagreement, your choice of entity, and the rationale for
your choice.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Answer Comment:
Document Name:
Yes
0
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
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0
Thomas Foltz - AEP - 5 -
Selected Answer:
Answer Comment:
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0
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0
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Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Yes
Answer Comment:
The standard needs to be more specific how a RAS entity is
determined. In addition, the Planning Coordinator should be considered
as a RAS-entity (please see our comment under Q10).
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Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Answer Comment:
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Yes
0
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Brian Bartos - CPS Energy - 3 -
Selected Answer:
Yes
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Answer Comment:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
No
Dominion believes it is appropriate to designate the RAS-entity to
provide information contained in Attachment 1. However, if the request
is for information contained in Attachments 2 or 3, Dominion believes
the designated entity should be the RC.
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Answer Comment:
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Yes
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0
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Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
Yes
Answer Comment:
Answer Comment:
RAS-owner and RAS-entity should also be NERC defined terms.
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0
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Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
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Answer Comment:
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Yes
0
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0
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Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Yes
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0
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Answer Comment:
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
Selected Answer:
No
RAS-entity is an undefined term and not reflected in the Functional
Model. In most cases the entity is probably also a GOP or TOP but
could be an entity who is neither of these. Unless the RAS-entity is
defined as an identified, enforceable Functional Entity, compliance and
reliability authority becomes unclear
0
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Gul Khan - Oncor Electric Delivery - 2 - TRE
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Answer Comment:
Selected Answer:
No
Since the Regional Entity will be keeping the database on each RAS,
there is no need for any entity to go to the RAS Entity for
information. This requirement places extra compliance burden on the
RAS Entity to provide addition information unnecessarily.
0
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Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
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Answer Comment:
Selected Answer:
Answer Comment:
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0
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0
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Yes
Answer Comment:
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0
0
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
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Answer Comment:
0
Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Yes
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0
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Answer Comment:
Selected Answer:
No
Answer Comment:
The RAS-entity being the entity to provide the detailed RAS information
to other registered entities should be the Transmission Planner or
FRCC Planning Coordinator since they study the reliability impact of the
RAS and maintain the system models.
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Answer Comment:
Yes
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0
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Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
0
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Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
Yes
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0
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0
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Answer Comment:
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
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0
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0
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
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Selected Answer:
Answer Comment:
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0
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Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
We agree there should be one primary equipment owner responsible
for submitting the data. However, we believe all requirements
applicable to the RAS-owner should actually apply to RAS-entity for
simplicity. Otherwise, the simplicity of using a RAS-entity is not
realized. Using RAS-entity for only a sub-set of requirements does not
reduce the complexity of the standard.
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Yes
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David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Yes
Answer Comment:
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0
Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc.:
Regions and RCs will establish (have established) their own procedures
and requirements for exchange of detailed RAS data/model. The
requirement for providing general RAS data/model could be handled
by the MOD‐032 standard.
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Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
The SDT should consider giving more rationale or guidelines on the
roles of the RAS-owner and RAS-entity and how to appropriately define
the RAS-entity.
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Answer Comment:
Selected Answer:
No
Answer Comment:
Please see 12 above. The RAS-entity should be confirming the model
after functional tests are performed in R9 and providing the model to its
Transmission Planner and Reliability Coordinator. The TP and RC are
in the best position to use the models and coordinate with adjacent
entities in this standard and other standards.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
No
Answer Comment:
Texas RE recommends clarity regarding how an entity is designated a
“RAS-entity”. It is not clear if it is the same as the RAS-owner. With no
requirement to designate a RAS-entity, it is not clear who would be
responsible for the reliability requirements if there is no RAS-entity
designated.
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
No
Answer Comment:
Comments: Hydro One Networks Inc.:
Regions and RCs will establish (have established) their own procedures
and requirements for exchange of detailed RAS data/model. The
requirement for providing general RAS data/model could be handled
by the MOD‐032 standard.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
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Yes
0
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
Selected Answer:
Yes
Along with the Planning Coordinator (please see our comment
under Q10).
Note - These SRC comments represent a consensus of the
ISOs/RTOs with the exception of ERCOT.
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Yes
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
Answer Comment:
Yes
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0
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0
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Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Yes
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0
0
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
Yes
Answer Comment:
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0
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14.
If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Barbara Kedrowski - We Energies - Wisconsin Electric Power Co. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
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0
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John Fontenot - Bryan Texas Utilities - 1 -
Selected Answer:
Answer Comment:
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Applicability Section 4.1.4 – The term “RAS-entity” is vague and not
self-explanatory. We would prefer that the standard only refer to “RASowners” and the requirements use wording like “ each RAS-owner,
individually or jointly . . .”. Otherwise, if the representative approach is
retained, then we suggest using an alternative label, such as “RASagent” or “RAS-representative” to be more closely aligned with the
entity’s function.
R1, Rationale, sentence 2 – The definition of “functional modification”
should be qualified further with wording like, “is any alteration of a RAS
that leads to the performance of a different operational objective or
action. The replacement of RAS components, the changing of RAS
settings or software upgrade does not modify the RAS functionality, if
the intended operational objective or result is achieved.
R3 - We suggest that “mutually agreed upon” be added in R3. The
RAS-entity should have some reasonable check and balance to the RC
identified reliability related issue.
R5, R6, R7 - We suggest that “or mutually agreed upon time-frame” be
added in R5 and R7. The RAS-entity and the RC should have the
flexibility to agree upon a time that a corrective action plan is needed
based upon workloads and risk. A one-size fits all approach does not
benefit system reliability or risk-based concepts.
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Thomas Foltz - AEP - 5 -
Selected Answer:
Answer Comment:
Clarity is needed in R4 as to exactly what the trigger is for the 60 full
month periodic review. Is it tied, perhaps, to the in‐service status? In
addition, rather than a 60 full month periodic review, AEP suggests a
“5 calendar year” review. This would allow flexibility for an entity to
integrate this work into its annual planning cycle.
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Leonard Kula - Independent Electricity System Operator - 2 -
Selected Answer:
Answer Comment:
The standard requires only one RC to review the RASs that are located
in its area of responsibility. There are RASs that in case of incorrect
operation or failure could affect a neighboring entity even if they are
located in one area. In these cases should the standard require a
coordinated review with the affected neighbors?
The standard requires reviewing of the new or modified RASs. What
level of modification would trigger a review for a RAS that was in
service before the standard becomes effective? Please specify.
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Andrew Pusztai - American Transmission Company, LLC - 1 -
Selected Answer:
Answer Comment:
Applicability Section 4.1.4 – The term “RAS-entity” is vague and not
self-explanatory. ATC would recommend that the standard only refer to
“RAS-owners” and the requirements be reworded such as “each RASowner, individually or jointly . . .” Otherwise, if the representative
approach is retained, then we suggest using an alternative label, such
as “RAS-agent” or “RAS-representative” to be more closely aligned with
the entity’s function.
R1, Rationale, sentence 2 – The description of “functional modification”
should be qualified further with wording such as, “is any alteration of a
RAS that leads to the performance of a different operational objective or
action. The replacement of RAS components, the changing of RAS
settings or upgrading software does not modify the RAS functionality, if
the intended operational objective or result is achieved.
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Brian Bartos - CPS Energy - 3 -
Selected Answer:
Answer Comment:
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Louis Slade - Dominion - Dominion Resources, Inc. - 6 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Dominion suggests that the explanation from footnote 13, Page 16,
from the SCPS Technical Report, be added into the Supplemental
material to help identify the purpose of “4.1.4 RAS‐entity – the
Transmission Owner, Generator Owner, or Distribution Provider
designated to represent all owners of the RAS.”
Dominion agrees with the recommendation contained in the SCPS
Technical report (page 17) that states “When deciding whether to
approve an SPS, the Reliability Coordinator and the Planning
Coordinator in whose area the SPS is to be installed or modified should
be required to consider supporting information provided with the
application; comments from Transmission Planners, Transmission
Operators, and Balancing Authorities and other Reliability Coordinators
and Planning Coordinators; and any supplemental information provided
by the SPS owner. “ and suggests it be incorporated into the
Supplemental Material.
Dominion does not see the need to use the word ‘full’ before calendar
month in the Supplemental Material and is concerned that its use in this
standard could result in uncertainty surrounding the use of calendar
month in other standards.
Attachment 1, Section II refers to Table 1, Category P7. What is the
relevance to making reference to Category P7 uniquely and specifically
(tower line or bipolar DC line)?
Attachment 1, Section III-Implementation states, “Documentation
describing the functional testing process.” Dominion recommends
deleting this bullet. This information is not necessarily available during
the early preliminary design stage. The approval of the design is
sought prior to detailed engineering.
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6 -
Selected Answer:
Answer Comment:
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Jared Shakespeare - Peak Reliability - 1 -
Selected Answer:
Answer Comment:
The revised PRC-012 addresses new RAS, retired RAS, and
functionally modified RAS. The revised Standard does not address
existing RAS, and therefore neglects any potential reliability issues
associated with them. Peak believes that existing RAS should not be
automatically grandfathered and that there should be a one-time
process to review existing RAS in accordance with the new PRC-012.
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Jeni Renew - SERC Reliability Corporation - 10 - SERC
Error: Subreport could not be shown.
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Answer Comment:
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Kathleen Goodman - ISO New England, Inc. - 2 - NPCC
Selected Answer:
Answer Comment:
Language in R4 should be changed to allow for an “assessment” to
lessen the level of review if no changes occur to the RAS or the area
electric system RAS is designed to protect. Suggest the following
language:
R4. Each Transmission Planner shall perform an assessment of each
RAS within its planning area at least once every 60 full calendar months
and provide the RAS‐owner(s) and the Reliability Coordinator(s) the
results including any identified deficiencies. Each evaluation shall
determine whether: [Violation Risk Factor:] [Time Horizon:]
There should be a phased in implementation plan for RC review of
existing RAS installations. If the Implementation Plan contemplates a
review of all existing RAS installations then that would be an
overwhelming task.
R4.3, Attachment 1 and Attachment 2:
All three items state the performance requirements for inadvertent
operation of an RAS are the same as those for the condition that it was
installed. This is not the correct metric to use. All of the performance
requirements in the TPL should be met if there is inadvertent operation.
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Error: Subreport could not be shown.
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Answer Comment:
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Gul Khan - Oncor Electric Delivery - 2 - TRE
Selected Answer:
Answer Comment:
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Darnez Gresham - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3 - MRO
Selected Answer:
Answer Comment:
MidAmerican has concerns about “redundancy” and “guidance” to steer
SPS / RAS designs and mandatory requirements. The language needs
to be modified to strike the “appropriate level of redundancy” and
replace it with a concept that the “design of the RAS / SPS must meet
its performance objective within the TPL requirements even with single
component failure. The RAS / SPS just has to survive a single
component failure and still achieve its reliability objective. The method
or “how” this is achieved should be left to the RAS / SPS owner with
input from the regional RC.
MidAmerican suggests that wording in Attachment 1, Section III be
modified to concentrate on the “design” of the RAS / SPS rather than
specifying a narrow interpretation of redundancy.
"Documentation showing that the design of the RAS is such that a
single RAS component failure, when the RAS is intended to operate,
does not prevent the interconnected transmission system from meeting
the same performance requirements (defined in Reliability Standard
TPL‐001‐4 or its successor) as those required for the System events
and conditions for which the RAS was designed. The documentation
should describe or illustrate how the implementation design achieves
this objective."
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christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -
Selected Answer:
Answer Comment:
As RASs may have an impact in both the long and short-term horizons,
ERCOT recommends that the SDT consider revising the standards as
set forth above to ensure that such coordination and associated
information exchanges occurs.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Duke Energy requests further clarification on the use of varying
measurements of time. In multiple places throughout the standard,
the drafting team uses the measurement of “full calendar months”.
In other places (R6 and R11) the measurement “calendar-days” is
used. We request more clarification on the difference between the
two, or a revision wherein only one measurement is used for
consistency.
Duke Energy suggests that Attachments 1 and 2 be changed from
bullets to numbers or letters so every item is referenced clearly
and unambiguously.
On Attachment 1. Section III – Implementation. Fourth bullet, Duke
Energy suggests moving it to Section II - Functional Description
and Transmission Planning Information before the Fifth Bullet.
On Attachment 1. Section II – Functional Description and
Transmission Planning Information. The fifth bullet should include
language to address “adequate level of redundancy” and “single
RAS component failure”. These two definitions are too vague and
might lead to very different interpretation depending to the type of
RAS.
Duke Energy requests clarification regarding how PRC-012-2 will
address the failure to operate and inadvertent operation of a “fully
redundant” RAS (i.e.,D12 and D13 in the present TPL standards). If
does not appear that they are addressed in the present draft.
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Michael Moltane - International Transmission Company Holdings Corporation - 1 -
Selected Answer:
Answer Comment:
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Answer Comment:
No comment.
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Terry BIlke - Midcontinent ISO, Inc. - 2 -
Selected Answer:
Answer Comment:
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Eric Senkowicz - Florida Reliability Coordinating Council - NA - Not Applicable - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Our thanks for the drafting team's efforts on trying to improve the clarity
of the standards with respect to RASs.
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Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
The definitions for “Functionally Modified” as used in Attachments 1 and
2 should be included in definitions specifically used in this standard,
and not in footnotes.
“Power System” is used throughout the body of the standard. Should it
be Bulk Electric System?
Requirement R2 stipulates that each reviewing Reliability Coordinator
has four calendar months, or on a mutually agreed upon schedule after
receipt of Attachment 1 materials to perform a review of the RAS in
accordance with Attachment 2. There should be an upper bound put on
a mutually agreed upon schedule to prevent excessively long times for
this review to take place.
Requirement R5, as written, suggests that independent Corrective
Action Plans should be submitted by each RAS-owner. It is proposed to
change this to “RAS-entity,” “RAS-entity in coordination with all RASowners” or “all RAS-owners shall jointly”.
Requirement R6, as written, suggests that independent analyses
should be performed by each RAS-owner. It is proposed to change this
to “RAS-entity,” “RAS-entity in coordination with all RAS-owners” or “all
RAS-owners shall jointly”.
Requirement R7, as written, suggests that independent Corrective
Action Plans should be submitted by each RAS-owner. It is proposed
to change it to “RAS-entity”, “RAS-entity in coordination with all RASowners” or “All RAS-owners shall jointly”.
Requirement R9 stipulates that “At least once every six calendar years,
each RAS-owner shall perform a functional test of each RAS to verify
the overall RAS performance and the proper operation of nonProtection System components.” An overall test includes Protection
System components, as well as non-Protection System components,
and operating any system equipment. Is this the intent of the
Requirement?
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Answer Comment:
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
FMPA agrees with comments submitted by FRCC Reliability
Coordinator.
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Jason Marshall - ACES Power Marketing - 6 - MRO,WECC,TRE,SERC,SPP,RFC
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
Requirement R1 is redundant with TPL standards. Since a RAS is
installed to address reliability issues, it is, in essence, also installed to
address performance requirements in planning studies. Thus,
installation will have already been studied and addressed in the TPL
studies (see Part 2.7.1). Since the Planning Coordinator is the
reliability entity that should be reviewing and approving RAS, there
would be no additional need to include Requirement R1 to submit this
data as the Reliability Coordinator can and should get the information
from the Planning Coordinator.
We are concerned that the Rationale Box for R3 implies that the
Reliability Coordinator should be approving the trade-offs between
dependability and security made by the equipment owners. We
disagree. The Reliability Coordinator should simply be aware of how
the RAS operates and the associated risks of Misoperation so that they
can model in their operational studies.
We are concerned that there are overlaps with the TPL
standards. Some have been mentioned in other questions. We won’t
repeat those here. However, we are concerned that R4 is
redundant. Wouldn’t the TP already be required to perform an
evaluation of each RAS in the TPL standards since they have to
consider RAS explicitly? TPL-001-4 Part 2.7.4 requires the “continued
validity” of CAPs developed to address meeting performance
requirements of the TPL standards to be reviewed annually. Since
CAPs can include installation of RAS, this implies that study will be
performed annually by the PC and TP to verify the RAS.
Part 4.3 should not reference the TPL standards. The performance
requirements of the TPL standards stand alone and will be met. There
is no need to reference them in this standard and potentially create
redundancy and double jeopardy issues.
The measures need significant improvement as they are very
generic. In general, they provide no more detail or guidance on how to
demonstrate or measure compliance with the requirement. They
primarily state that the applicable entity should have dated and timestamped documentation which is basic requirement for any
evidence. This is generic enough that a single generic measurement
could be written to replace them.
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0
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0
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Chris Scanlon - Exelon - 1 -
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
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0
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David Jendras - Ameren - Ameren Services - 3 -
Selected Answer:
Answer Comment:
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0
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Paul Malozewski - Hydro One Networks, Inc. - 3 -
Selected Answer:
Answer Comment:
Hydro One Networks Inc.:
1)RAS are required for the reliability of the power system and
compliance with the NERC reliability standards. As such, it is not the
RAS owner who would decide on the need for a new or modified RAS
and its functional specification. Instead, it is the TP who determines if
a new RAS is needed or a RAS needs to be modified to meet the TPL‐
001‐4 or other requirements. Just as R4 of PRC‐012‐2 requires “Each
Transmission Planner shall perform an evaluation of each RAS within
its planning area at least once every 60 full calendar months”, it is only
logical that before adding a new RAS or modifying an existing RAS, the
TP should perform an evaluation and determine its functional
specification. This must be the first requirement in PRC‐012‐2, similar
to R1 of PRC‐010‐1/2.
2)The RAS owners design and engineer the RAS to meet the functional
requirements specified by the TP.
3)Then R1 (which becomes R2) should ask the TP who has done the
evaluation of new or modified RAS (not the RAS owner) to provide the
information to RC, unless the TP and RC functions are performed by
the same organization. TP has the information in Part II of the checklist
in Attachment 1. Part III is the information that RAS owner can
provide to TP or to RC.
Document Name:
Likes:
1
Dislikes:
Hydro One Networks, Inc., 1, Farahbakhsh Payam
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Answer Comment:
None
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0
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Answer Comment:
The scope of PRC-012-2 should be limited to cover RAS that are
needed to meet the performance requirements of Table 1 in TPL-001-4
for disturbances in category P1 through P7 in order to remove extreme
disturbances from the scope of the standard.
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0
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -
Selected Answer:
Answer Comment:
Texas RE is concerned there is there is a reliability gap in the
determination of UVLS and its relationship to several standards projects
including this one. In Project 2008-02.2 UVLS there is indication in the
technical guide that certain UVLS will not be in a UVLS Program but
would be considered a RAS yet the definition of RAS may exclude
those UVLS systems. Texas RE acknowledges the need for flexibility,
however, too much flexibility could cause reliability gaps that are
supported by the language of the standards.
It appears in several projects many UVLS relays will now not be
analyzed for misoperations (PRC-004-5), will not be in a UVLS Program
(PRC-010), will not be considered a RAS (PRC-012-2) and will not be
maintained per PRC-005. Texas RE requests the SDTs review these
projects and determine the impacts thereof.
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 -
Selected Answer:
Answer Comment:
Hydro One Networks Inc.:
1)RAS are required for the reliability of the power system and
compliance with the NERC reliability standards. As such, it is not the
RAS owner who would decide on the need for a new or modified RAS
and its functional specification. Instead, it is the TP who determines if
a new RAS is needed or a RAS needs to be modified to meet the TPL‐
001‐4 or other requirements. Just as R4 of PRC‐012‐2 requires “Each
Transmission Planner shall perform an evaluation of each RAS within
its planning area at least once every 60 full calendar months”, it is only
logical that before adding a new RAS or modifying an existing RAS, the
TP should perform an evaluation and determine its functional
specification. This must be the first requirement in PRC‐012‐2, similar
to R1 of PRC‐010‐1/2.
2)The RAS owners design and engineer the RAS to meet the functional
requirements specified by the TP.
3)Then R1 (which becomes R2) should ask the TP who has done the
evaluation of new or modified RAS (not the RAS owner) to provide the
information to RC, unless the TP and RC functions are performed by
the same organization. TP has the information in Part II of the checklist
in Attachment 1. Part III is the information that RAS owner can
provide to TP or to RC.
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0
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Error: Subreport could not be shown.
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Daniela Hammons - CenterPoint Energy Houston Electric, LLC - 1 - TRE
Selected Answer:
Answer Comment:
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0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 -
Error: Subreport could not be shown.
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Answer Comment:
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 -
Selected Answer:
Answer Comment:
Tacoma Power recommends that the definition of ‘RAS-owner’ be
limited to functional ownership, as opposed to component
ownership. For example, if one company owns a station DC supply,
some wiring, and trip coil, but another company owns the control device
at the same location, the entity that owns the control device should be a
RAS-owner, and the entity that owns the station DC supply, wiring, and
trip coil should not be a RAS-owner. Another example would be an
entity that owns sensing devices that another entity uses to provide
inputs to a relay or PLC that it owns; the entity that owns the sensing
devices in this example should not be a RAS-owner. Yet another
example is when one entity owns a portion of the communications
system; simply owning part of the communications system should not
make the entity a RAS-owner.
Under Requirements R5, R6, R7, and R9, responsibility should be that
of the RAS-entity, not the RAS-owner(s). Yes, RAS-owners may
participate in fulfilling these requirements, but the RAS-entity should be
the liaison. This proposed change may necessitate an additional
requirement for RAS-owners to designate one RAS-entity for each
RAS; in the event that consensus cannot be obtained among RASowners, the Reliability Coordinator should designate the RAS-entity.
Examples of what is and is not a functional modification would be
beneficial.
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0
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
None.
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0
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0
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Rico Garcillano - Pacific Gas and Electric Company - NA - Not Applicable - WECC
Selected Answer:
Answer Comment:
More clarity needs to be provided in terms of what counts as a
functional modification as it is too subjective right now.
An example is if a line which is currently monitored as an outage for a
scheme is bisected by a new looped sub, the scheme would be
modified to monitor the two "new" lines created by new sub.
The conservative approach would be to submit for review and present
the changes. But I would argue that if the load/gen is minimal, and the
RAS actions are unchanged, a presentation and detailed review is not
needed. If the RAS actions change as a result of the new sub, then I
can see a review being required. Additionally, if a changes in the RAS
actions are to take additional actions already part of the scheme, a less
detailed reviewed could be required; vice versa, if new RAS actions are
required, a more detailed review may be needed.
It may seem trivial, but with the amount of Capital investment going into
our Transmission System right now, presenting every minor change
that truly doesn't modify the functionality of a scheme would be a huge
strain on resources.
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Selected Answer:
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies important [JSW1]reliability- related considerations for the
Reliability Coordinator (RC) to review and verify for each new or functionally modified2 RAS.
The RC review is not limited to the RAS checklist items and the RC may request additional
information on any reliability issue related to the RAS.
Determination of Review Level
RAS can have varying impacts on the power System. RAS with more significant impact
[WTL2]require a higher level of review than those having a lesser impact. [JSW3]The RC will
determine tThe level of review by the RC may be limited ifbased on the System response for a
failure of the RAS to operate or if the inadvertent operation of the RAS could not result in any
of the following conditions:
•
•
•
frequency‐related instability
unplanned tripping of load or generation
uncontrolled separation or cCascading[JSW4] outages
If there is the potential for any of the conditions above to occur may be produced, the entire RC
RAS review checklist should include below should be followed. the RAS Designfollowing criteria
below.:
RAS retirement reviews may use an abbreviated format that concentrates on the Planning
justifications describing why the RAS is no longer needed. Implementation issues will seldom
require removal review.[JSW5]
RAS DESIGN
System Performance Objectives – - The The RAS actions satisfy System performance
objectives for the scope of System events and conditions that the RAS is intended to
mitigate.
Arming Conditions - The RAS arming conditions, if applicable, are appropriate to its
System performance objectives.
Adverse Interactions – The - The RAS avoids adverse interactions with other
RAS, Pprotection Ssystem[JSW6](s), control system(s), and Ooperating
Pprocedure[JSW7](s).
Misoperations – The effects of RAS incorrect operation, including inadvertent
operation and failure to operate (if non‐operation for RAS single component
failure is acceptable), have been identified.
•
The inadvertent operation of the RAS satisfies the same performance requirements as
those required for the contingency for which it was designed. For RAS that are
installed for conditions or contingencies for which there are no applicable System
performance requirements, the inadvertent operation satisfies the System
performance requirements of Table 1, Category P7 of NERC Reliability Standard TPL‐
Draft 1 of PRC‐012‐2 – Remedial Action Schemes
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Attachments
001‐4 or its successor.
Future Plans – The effects of future System plans on the design and operation of
the RAS, where applicable, have been identified.
2
Functionally Modified:
Any modification to a RAS beyond the replacement of components that preserve the original functionality is a
functional modification.
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Attachments
The effects of future System plans on the design and operation of the RAS,
where applicable, have been identified.
RAS IMPLEMENTATION
RAS Logic – The c - The implementation of RAS logic appropriately correlates desired
actions (outputs) with System events and conditions (inputs).
Appropriate Timing - – The The timing of RAS action(s) is appropriate to its System
performance objectives.
Single Failure Expectations – A A single component failure in a RAS does not prevent
the BES from meeting the same performance requirements as those required for the
System events and conditions for which the RAS was designed.
Testing and Maintenance - – The The RAS design facilitates periodic testing and
maintenance.
RAS Arming - – The The mechanism or procedure by which the RAS is armed is clearly
described, and is appropriate for reliable arming and operation of the RAS for the
System conditions and events for which it is designed to operate.
Redundancy – RAS - RAS automatic arming, if applicable, has the same degree of
redundancy as the RAS itself.
RAS retirement reviews may use an abbreviated format that concentrates on the
Planning justifications describing why the RAS is no longer needed. Implementation issues
will seldom require removal review.
Draft 1 of PRC‐012‐2 – Remedial Action Schemes
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ERCOT Nodal Operating Guides
11.2
Special Protection System
(1)
Special Protection Systems (SPSs) are protective relay systems designed to detect
abnormal ERCOT System conditions and take pre-planned corrective actions to maintain
a secure system.
(2)
In addition to the requirements in the Protocols and applicable North American Electric
Reliability Corporation (NERC) Reliability Standards, SPSs shall also meet the following
requirements:
(a)
The SPS owner shall coordinate the design and implementation of the SPS with
the owners and operators of Facilities included in the SPS, including but not
limited to Generation Resources, Transmission Service Providers (TSPs) and
Direct Current Ties (DC Ties);
(b)
The SPS shall be automatically armed when appropriate;
(c)
The SPS shall not operate unnecessarily. To avoid unnecessary SPS operation,
the SPS owner may provide a Real-Time status indication to the owner of any
Generation Resource controlled by the SPS to show when the flow on one or
more of the SPS monitored Facilities exceeds 90% of the flow necessary to arm
the SPS. The cost necessary to provide such status indication shall be the
responsibility of the SPS owner;
(d)
The status indication of any automatic or manual arming/activation or operation of
the SPS shall be provided as Supervisory Control and Data Acquisition (SCADA)
alarm inputs to the owners of any Facility controlled by the SPS;
(e)
When an SPS is removed from service, the SPS owner or its Designated Agent
shall immediately notify ERCOT;
(f)
When an SPS is returned to service, the SPS owner or its Designated Agent shall
immediately notify ERCOT. ERCOT shall modify its reliability constraints to
recognize the availability of the SPS;
(g)
The SPS owner shall telemeter the status indication of the following items by
SCADA to ERCOT for incorporation into ERCOT systems:
(i)
Any automatic or manual arming/activation or operation of the SPS;
(ii)
The in-service/out-of-service status of the SPS; and
(iii)
Any additional related telemetry that already exists pertinent to the
monitoring of the SPS (e.g. status indication of communications links
between associated SPS equipment and the owner’s control center, arming
limits of associated SPS equipment).
(h)
(4)
The TSP may receive telemetry for a Resource Entity owned SPS through
ERCOT or through the SPS owner, at the option of the TSP. The SPS owner, at
its own cost, must provide telemetry for Resource Entity owned SPSs to the TSP
upon request.
The owners of an existing, modified, or proposed SPS shall submit documentation of the
SPS to ERCOT for review and compilation into an ERCOT SPS database. The
documentation shall detail the design, operation, functional testing, and coordination of
the SPS with other protection and control systems.
(a)
ERCOT shall conduct a review of each proposed SPS and each proposed
modification to an existing SPS. Additionally, it shall conduct a review of each
existing SPS at least every five years as required by changes in system
conditions. Each review shall proceed according to a process and timetable
documented in ERCOT Procedures and shall be posted on the Market Information
System (MIS) Secure Area.
(b)
The review of a proposed SPS shall be completed before the SPS is placed in
service, unless ERCOT specifically determines that exemption of the proposed
SPS from the review completion requirement is warranted. The timing of placing
the SPS into service must be coordinated with and approved by ERCOT. The
implementation schedule must be confirmed through submission of a Network
Operations Model Change Request (NOMCR) to ERCOT.
(c)
Existing SPSs that have already undergone at least one review shall remain in
service during any subsequent review. Modifications to existing SPSs may be
implemented upon approval by ERCOT.
(d)
The process and schedule for placing an SPS into service must be consistent with
documented ERCOT Procedures. The schedule must be coordinated among
ERCOT and the owners of the Facility controlled by the SPS, and shall provide
sufficient time to perform any necessary testing prior to its being placed in
service.
(e)
ERCOT review of an SPS shall:
(i)
Identify any conflicts with the Protocols, NERC Reliability Standards, and
these Operating Guides;
(ii)
Evaluate and document the consequences of failure of a single component
of the SPS, which would result in failure of the SPS to operate when
required; and
(iii)
Evaluate and document the consequences of misoperation, incorrect
operation, or unintended operation of an SPS, when considered by itself
and without any other system contingency.
(iv)
Upon completion of ERCOT’s SPS review, ERCOT shall provide all
results and underlying studies to the SPS owner.
(f)
If deficiencies are identified by ERCOT or other parties’ comments, the SPS
owner shall either submit an amended SPS proposal or withdraw the SPS
proposal. The amended SPS proposal shall undergo the review process specified
in item (e) above until the identified deficiencies have been resolved to the
satisfaction of ERCOT.
(g)
As part of the ERCOT review, ERCOT shall notify the Steady State Working
Group (SSWG), the Dynamics Working Group (DWG), and the System
Protection Working Group (SPWG) of the SPS proposal, and each working group
or any member of each working group may provide any comments, questions, or
issues to ERCOT. ERCOT may work with the owner(s) of Facilities controlled
by the SPS as necessary to address all issues.
(h)
ERCOT shall develop a method to include the SPS in Security-Constrained
Economic Dispatch (SCED), Outage coordination, and Reliability Unit
Commitment (RUC).
(i)
ERCOT’s review shall provide an opportunity for and include consideration of
comments submitted by Market Participants affected by the SPS.
PRC‐012‐2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 1 of PRC‐012‐2 corrects the applicability of the fill‐in‐the‐blank standards (PRC‐012‐1,
PRC‐013‐1, and PRC‐014‐1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk‐Power System, and incorporates the reliability objectives of
all the RAS/SPS‐related standards. Draft 1 contains nine requirements and measures, the
associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. Draft 1of PRC‐012‐2 is posted for a 45‐day initial formal comment period with a
parallel initial ballot in the last ten days of the comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC‐012‐2 posted for informal comment
April 30 – May 20, 2015
45‐day formal comment period with initial ballot
August 20 – October 5,
2015
Anticipated Actions
Date
10‐day final ballot
December 2015
NERC Board (Board) adoption
February 2016
Draft 1 of PRC‐012‐2
August 2015
Page 1 of 42
PRC‐012‐2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
3.
Number:
Purpose:
PRC‐012‐2
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Transmission Planner
4.1.3. RAS‐owner – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.1.4. RAS‐entity – the RAS‐owner designated to represent all RAS‐owner(s) for
coordinating the review and approval of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC‐012‐2.
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PRC‐012‐2 – Remedial Action Schemes
B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement (removal from service) must be completed prior to
implementation or retirement. A functional modification is any modification to a RAS
beyond the replacement of components that preserves the original functionality.
To facilitate a review that promotes reliability, the RAS‐entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS‐entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. In cases where a RAS crosses one or more RC Area
boundaries, each affected RC is responsible for conducting either individual reviews or a
coordinated review.
R1.
Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS‐entity shall submit the information identified in Attachment 1 for
review to the Reliability Coordinator(s) that coordinates the area(s) where the RAS is
located. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest‐area reliability perspective of all functional entities
and an awareness of reliability issues in any neighboring RC Area. This Wide Area purview
provides continuity in the review process and facilitates the evaluation of interactions
among separate RAS as well as interactions among RAS and other protection and control
systems. Including the RC also minimizes the possibility of a conflict of interest that could
exist because of business relationships among the RAS‐entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning
or implementation of a RAS. The RC may request assistance in RAS reviews from other
parties such as the PC or regional technical groups; however, the RC will retain the
responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each RAS submitted.
The time frame of four‐full‐calendar months is consistent with current utility and regional
practice; however, flexibility is provided by allowing the parties to negotiate a mutually
agreed upon schedule for the review.
Draft 1 of PRC‐012‐2
August 2015
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PRC‐012‐2 – Remedial Action Schemes
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1, shall, within four‐full‐calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to the RAS‐entity. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS‐entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS‐entity to respond to the RC review is not necessary
because it is in the RAS‐entity’s interest to obtain an expeditious response from the
entity and thus ensure a timely implementation.
R3.
Following the review performed pursuant to Requirement R2, the RAS‐entity shall
address each identified issue and obtain approval from each reviewing Reliability
Coordinator prior to placing a new or functionally modified RAS in service or retiring
an existing RAS. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator in accordance with
Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every sixty‐full‐calendar months. The purpose of a periodic
RAS evaluation is to verify the continued effectiveness and coordination of the RAS, as
well as to verify that requirements for BES performance following an inadvertent RAS
operation or a single component failure in the RAS continues to be satisfied. A periodic
evaluation is needed because changes in system topology or operating conditions that
have occurred since the previous RAS evaluation—or initial review—was completed may
change the effectiveness of a RAS or the way it impacts the BES.
Sixty‐full‐calendar months, which begins on the effective date of the standard pursuant to
the implementation plan, was selected as the maximum time frame between evaluations
based on the time frames for similar requirements in Reliability Standards PRC‐006, PRC‐
010, and PRC‐014. The RAS evaluation can be performed sooner if it is determined that
material changes to system topology or system operating conditions have occurred that
could potentially impact the effectiveness or coordination of the RAS. The periodic RAS
Draft 1 of PRC‐012‐2
August 2015
Page 4 of 42
PRC‐012‐2 – Remedial Action Schemes
evaluation will typically lead to one of the following outcomes: 1) affirmation that the
existing RAS is effective; 2) identification of changes needed to the existing RAS; or, 3)
justification for RAS retirement.
The items required to be addressed in the evaluation are planning analyses that involve
modeling of the interconnected transmission system to assess BES performance;
consequently, the TP is the functional entity best suited to perform the analyses. To
promote reliability, the TP is required to provide the RAS‐owner(s) and each reviewing RC
with the results of the evaluation.
The previous version of this standard (PRC‐012‐0 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL‐001‐
0, TPL‐002‐0, and TPL‐003‐0) as that required of the contingency for which it was
designed, and not exceed TPL‐003‐0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise
and consistent with PRC‐012‐0 Requirement 1, R1.4, the RAS should be designed so that
its whole or partial inadvertent operation due to a single component malfunction satisfies
the system performance requirements for the same Contingency for which the RAS was
designed.
If the RAS was installed for an extreme event in TPL‐001‐4 or for some other Contingency
or System condition not defined in TPL‐001‐4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL‐001‐4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.3.1 – 4.3.5) are the ones that are
common to all planning events P0‐P7 listed in TPL‐001‐4.
R4.
Each Transmission Planner shall perform an evaluation of each RAS within its planning
area at least once every 60‐full‐calendar‐months and provide the RAS‐owner(s) and
the reviewing Reliability Coordinator(s) the results including any identified
deficiencies. Each evaluation shall determine whether: [Violation Risk Factor:
Medium] [Time Horizon: Long‐term Planning]
4.1. The RAS mitigates the System condition(s) or Contingency(ies) for which it was
designed.
4.2. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
4.3. The possible inadvertent operation of the RAS resulting from any single RAS
component malfunction satisfies all of the following:
4.3.1. The BES shall remain stable.
Draft 1 of PRC‐012‐2
August 2015
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PRC‐012‐2 – Remedial Action Schemes
4.3.2. Cascading shall not occur.
4.3.3. Applicable Facility Ratings shall not be exceeded.
4.3.4. BES voltages shall be within post‐Contingency voltage limits and post‐
Contingency voltage deviation limits as established by the Transmission
Planner and the Planning Coordinator.
4.3.5. Transient voltage responses shall be within acceptable limits as
established by the Transmission Planner and the Planning Coordinator.
4.4. A single component failure in the RAS, when the RAS is intended to operate,
does not prevent the BES from meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its successor) as those required for
the events and conditions for which the RAS is designed.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS‐owner(s) and the reviewing Reliability Coordinator(s) in
accordance with Requirement R4.
Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation is
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120‐calendar‐day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4
regarding the investigation of a Protection System Misoperation. To promote reliability,
each RAS‐owner is required to provide the results of RAS operational performance
analyses to each reviewing RC.
RAS‐owners may need to collaborate with their associated TP to comprehensively analyze
RAS operational performance. This is because a RAS operational performance analysis
involves verifying that the RAS operation triggers and responds (Parts 5.1, 5.2) and that
the resulting BES response (Parts 5.3, 5.4) is consistent with the intended functionality
and design of the RAS.
R5.
Each RAS‐owner shall, within 120‐calendar days of a RAS operation or failure of a RAS
to operate when expected, analyze the RAS performance and provide the results of
the analysis, including any identified deficiencies, to its reviewing Reliability
Draft 1 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
Coordinator(s). The RAS operational performance analysis shall determine whether:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
5.1. The System events and/or conditions appropriately triggered the RAS.
5.2. The RAS responded as designed.
5.3. The RAS was effective in mitigating BES performance issues it was designed to
address.
5.4. The RAS operation resulted in any unintended or adverse BES response.
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis in accordance with Requirement R5.
Rationale for Requirement R6: Deficiencies, identified either in the periodic RAS
evaluation conducted by the TP in Requirement R4 or in the analysis conducted by the
RAS‐owner pursuant to Requirement R5, are likely to pose a reliability risk to the BES. To
mitigate potential reliability risks, Requirement R6 mandates that the RAS‐owner develop
a Corrective Action Plan (CAP) that establishes the mitigation actions and timetable to
address the deficiency. If the CAP requires that a functional change be made to a RAS, the
RAS‐owner will need to submit information identified in Attachment 1 to the reviewing
RC(s) prior to placing RAS modifications in service per Requirement R1.
Depending on the complexity of the issues, development of a CAP might require study,
engineering, or consulting work. A time frame of six‐full‐calendar months is specified to
allow enough time for RAS‐owner collaboration on the CAP development, while ensuring
that deficiencies are addressed in a reasonable time.
R6.
Within six‐full‐calendar months of being notified of a deficiency in its RAS pursuant to
Requirement R4 or Requirement R5, each RAS‐owner shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its reviewing Reliability
Coordinator(s). [Violation Risk Factor: Medium] [Time Horizon: Operations Planning,
Long‐term Planning]
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications with each reviewing Reliability Coordinator in accordance with
Requirement R6.
Rationale for Requirement R7: Requirement R7 mandates the RAS‐owner(s) implement a
CAP (developed in Requirement R6) that mitigates the deficiencies identified in
Requirements R4 and R5. By definition, a CAP is: “A list of actions and an associated
timetable for implementation to remedy a specific problem.” The implementation of a
properly developed CAP ensures that RAS deficiencies are mitigated in a timely manner.
Each reviewing Reliability Coordinator must be notified if CAP actions or timetables
change.
Draft 1 of PRC‐012‐2
August 2015
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PRC‐012‐2 – Remedial Action Schemes
R7.
For each CAP submitted pursuant to Requirement R6, each RAS‐owner shall:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the appropriate Reliability
Coordinator(s) that documents the implementation or updating of a CAP in
accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non‐Protection System (control) components of a RAS that are not addressed in PRC‐005.
Protection System components that are part of a RAS are maintained in accordance with
PRC‐005. The drafting team selected a six‐calendar‐year testing interval to be consistent
with some of the maintenance intervals of various Protection System and Automatic
Reclosing components established in PRC‐005. This interval provides an entity the
opportunity to design its RAS functional testing program such that it coincides with the
testing of any associated PRC‐005 components.
The six‐calendar‐year interval, which begins on the effective date of the standard
pursuant to the implementation plan, is a balance between the resources required to
perform the testing and the potential reliability impacts to the BES created by
undiscovered latent failures that could cause an incorrect operation of the RAS. Extending
to longer intervals increases the reliability risk to the BES posed by a potentially
undiscovered latent failure that could cause an incorrect operation of the RAS. The RAS‐
owner is in the best position to determine the testing procedure and schedule due to its
overall knowledge of the RAS design, installation, and functionality. Functional testing
may be accomplished with end‐to‐end testing or a segmented approach. Each segment of
a RAS should be tested but overlapping segments can be tested individually negating the
need for complex maintenance schedules and outages. A correct operation of a RAS
qualifies as a functional test as long as all segments operate. If an event causes a partial
operation of a RAS, the segments without an operation will require a functional test
within the six year interval to be compliant with Requirement R8.
R8.
At least once every six‐calendar years, each RAS‐owner shall perform a functional test
of each RAS to verify the overall RAS performance and the proper operation of non‐
Draft 1 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
Protection System components. [Violation Risk Factor: High] [Time Horizon: Long‐term
Planning]
M8. Acceptable evidence may include, but is not limited to, dated documentation of the
functional testing in accordance with Requirement R8.
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high‐level information on existing RAS that can potentially impact the entities’
operational and/or planning activities. Attachment 3 lists the minimum information
required for the RAS database, which includes a summary of the RAS initiating conditions,
corrective actions, and System issues being mitigated. This information allows an entity to
evaluate the reliability need for requesting more detailed information from the RAS‐
entity identified in the database contact information. The RC is the appropriate entity to
maintain the database because the RC receives the required database information when
a new or modified RAS is submitted for review.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once each calendar year. [Violation Risk
Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was maintained in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
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August 2015
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PRC‐012‐2 – Remedial Action Schemes
The Transmission Owner, Generator Owner, and Distribution Provider shall each
keep data or evidence to show compliance with Requirements R1 through R9, and
Measures M1 through M9 since the last audit, unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
If a Transmission Owner, Generator Owner or Distribution Provider is found non‐
compliant, it shall keep information related to the non‐compliance until
mitigation is completed and approved, or for the time specified above, whichever
is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
Draft 1 of PRC‐012‐2
August 2015
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PRC‐012‐2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS‐entity failed to
submit the information
identified in Attachment 1 to
one or more of the Reliability
Coordinator(s) in accordance
with Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30‐calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30‐
calendar days but less than
or equal to 60‐calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60‐
calendar days but less than
or equal to 90‐calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90‐
calendar days.
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
Draft 1 of PRC‐012‐2
August 2015
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS‐entity failed to
obtain approval from each
reviewing Reliability
Coordinator prior to placing
a new or functionally
modified RAS in service or
retiring an existing RAS in
accordance with
Requirement R3.
R4.
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but in
greater than 60‐full‐calendar
months but less than 61‐full‐
calendar months.
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but in
greater than 61‐full‐calendar
months but less than 62‐full‐
calendar months.
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but in
greater than 62‐full‐calendar
months but less than 63‐full‐
calendar months.
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but in
greater than 63‐full‐calendar
months.
OR
OR
The Transmission Planner
failed to perform the
evaluation in accordance
with Requirement R4.
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1 through 4.4.
Draft 1 of PRC‐012‐2
August 2015
OR
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but failed
Page 12 of 42
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
to evaluate two or more of
the Parts 4.1 through 4.4.
OR
The Transmission Planner
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the RAS‐owner(s)
and the reviewing Reliability
Coordinator(s).
R5.
The RAS‐owner performed
the analysis in greater than
120‐calendar days, but less
than or equal to 130‐
calendar days in accordance
with Requirement R5.
The RAS‐owner performed
the analysis in greater than
130‐calendar days, but less
than or equal to 140‐
calendar days in accordance
with Requirement R5.
The RAS‐owner performed
the analysis in greater than
150‐calendar days.
The RAS‐owner performed
the analysis in greater than
140‐calendar days, but less
than or equal to 150‐
calendar days in accordance
with Requirement R5.
OR
The RAS‐owner failed to
perform the analysis in
accordance with
Requirement R5.
OR
The RAS‐owner performed
the analysis in accordance
with Requirement R5, but
failed to address one of the
Parts 5.1 through 5.4.
Draft 1 of PRC‐012‐2
August 2015
OR
The RAS‐owner performed
the analysis in accordance
with Requirement R5, but
failed to address two or
Page 13 of 42
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
more of the Parts 5.1
through 5.4.
OR
The RAS‐owner performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
to one or more of the
reviewing Reliability
Coordinator(s).
R6.
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10‐calendar days.
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10‐
calendar days but less than
or equal to 20‐calendar days.
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20‐
calendar days but less than
or equal to 30‐calendar days.
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30‐
calendar days.
OR
The RAS‐owner developed a
Corrective Action Plan and
failed to submit it to one or
more of its reviewing
Reliability Coordinator(s) in
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
accordance with
Requirement R6.
OR
The RAS‐owner failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS‐owner
N/A
implemented a CAP (Part
7.1), but failed to update the
CAP (Part 7.2) if actions or
timetables changed and
failed to notify one or more
of the reviewing Reliability
Coordinator(s) (Part 7.3), in
accordance with
Requirement R7.
N/A
The RAS‐owner failed to
implement a CAP (Part 7.1)
in accordance with
Requirement R7.
R8.
The RAS‐owner performed
the functional test for a RAS
as specified in Requirement
R8, but was less than or
equal to 30‐calendar days
late.
The RAS‐owner performed
the functional test for a RAS
as specified in Requirement
R8, but was more than 60‐
calendar days but less than
or equal to 90‐calendar days
late.
The RAS‐owner performed
the functional test for a RAS
as specified in Requirement
R8, but was more than 90‐
calendar days late.
The RAS‐owner performed
the functional test for a RAS
as specified in Requirement
R8, but was more than 30‐
calendar days but less than
or equal to 60‐calendar days
late.
OR
The RAS‐owner failed to
perform the functional test
Draft 1 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
for a RAS as specified in
Requirement R8.
R9.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30‐calendar days.
Draft 1 of PRC‐012‐2
August 2015
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30‐
calendar days but less than
or equal to 60‐calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90‐calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60‐
calendar days but less than
or equal to 90‐calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
Page 16 of 42
PRC‐012‐2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
Date
Action
Change Tracking
1
Adopted by NERC Board of Trustees
New
Draft 1 of PRC‐012‐2
August 2015
Page 17 of 42
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified1 RAS that the RAS‐entity shall document and provide to
the reviewing Reliability Coordinator(s) (RC) for review. If an item on this list does not apply
to a specific RAS, a response of N/A or Not Applicable for that item is appropriate. When a
RAS has been previously reviewed, only the proposed modifications to that RAS require
review; however, the RAS‐entity must provide a summary of the previously approved
functionality. The RC may request additional information on any reliability issue related to
the RAS. Additional entities (without decision authority) may be part of the RAS review
process at the request of the RC.
I. General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012, Requirements R5 and R7]
4. Data to populate the RAS database:
a. RAS name.
b. RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐
voltage, or slow voltage recovery).
e. Description of the contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
f. Action(s) to be taken by the RAS.
g. Any additional explanation relevant to high‐level understanding of the RAS.
1
Functionally Modified: Any modification to a RAS beyond the replacement of components that preserve the original
functionality is a functional modification.
Draft 1 of PRC‐012‐2
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Attachments
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
2. The action(s) to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed. [Reference NERC Reliability Standard PRC‐014, R3.2]
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
Documentation showing that the possible inadvertent operation of the RAS resulting
from any single RAS component malfunction satisfies all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
5. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
6. Identification of other affected RCs.
III. Implementation
1. Documentation describing the applicable equipment used for detection,
telecommunications, transfer trip, logic processing, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in service or is being
maintained.
Draft 1 of PRC‐012‐2
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Attachments
4. Documentation showing that a single component failure in the RAS, when the RAS is
intended to operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. The
documentation should describe or illustrate how the design achieves this objective.
[Reference NERC Reliability Standard PRC‐012, R1.3]
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS‐entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability‐related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified2 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any reliability issue related to the RAS.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
3. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
4. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate (if non‐operation for RAS single component failure is acceptable), have been
identified.
5. The possible inadvertent operation of the RAS resulting from any single RAS component
malfunction satisfies all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
6. The effects of future BES modifications on the design and operation of the RAS have
been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. The timing of RAS action(s) is appropriate to its BES performance objectives.
2
Functionally Modified:
Any modification to a RAS beyond the replacement of components that preserve the original functionality is a
functional modification.
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Attachments
3. A single component failure in a RAS does not prevent the BES from meeting the same
performance requirements as those required for the events and conditions for which
the RAS is designed.
4. The RAS design facilitates periodic testing and maintenance.
5. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
Draft 1 of PRC‐012‐2
August 2015
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Attachments
Attachment 3
Database Information
1. RAS name.
2. RAS‐entity and contact information.
3. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Any additional explanation relevant to high‐level understanding of the RAS.
Draft 1 of PRC‐012‐2
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Supplemental Material
Technical Justifications for Requirements
Applicability
4.1.4 RAS‐entity
The purpose of the RAS‐entity is to be the single information conduit with each reviewing
Reliability Coordinator (RC) for all RAS‐owners for each RAS. The RAS‐entity needs to
coordinate all review materials and any presentations. If all of the RAS equipment has a single
owner, then the RAS‐entity is the same as the RAS‐owner and that owner speaks for itself.
If the RAS equipment has more than one owner, then each separate RAS equipment owner is a
RAS‐owner. The RAS‐entity will always be one of these RAS‐owners. A RAS‐entity will be
selected by all RAS‐owners and, traditionally, has usually been the owner of the RAS controller
and a Transmission Owner. If a specific RAS‐entity is not identified by the RAS‐owners, the RC
will assign that function to the RAS‐owner who provides the review material to them.
The RAS‐owner(s); i.e., Transmission Owner(s), Generator Owner(s), or Distribution Provider(s)
who are not the RAS‐entity still have responsibilities as assigned in other NERC Reliability
Standards, such as equipment maintenance. In addition, when RAS modifications are needed,
each RAS‐owner of RAS equipment that must be modified must accept the specific
responsibilities assigned to them as described in the necessary Corrective Action Plan (CAP), or
otherwise as described in the revised Attachment 1.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Any modification to RAS hardware beyond the substitution of components that merely
preserve the original functionality is a functional modification. Any change in RAS logic such as
new inputs or outputs, or any other modification that affects overall RAS functionality, or
redundancy level as documented in the original submission for review are functional
modifications. RAS modifications identified by a CAP pursuant to Requirement R6 beyond the
substitution of components that merely preserve the original functionality are functional
modifications. RAS removal is essentially a form of RAS functional modification. Any RAS
proposed for removal needs to be evaluated under the RAS Retirement section of the
Attachment 1 checklist.
To facilitate a review that promotes reliability, the RAS‐entity must provide the reviewer with
sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS‐entity provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
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individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS‐entity must
provide Attachment 1 data to the reviewing RC. The information will need to be submitted
early enough to allow RC review in the allotted time pursuant to Requirement R2, including
resolution of any issues that might be identified, in order to obtain approval of the reviewing
RC. Expeditious submittal of this information is in the interest of each RAS‐owner to effect a
timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS‐owner(s). An independent review by a multi‐disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the
widest‐area reliability perspective of all functional entities and an awareness of reliability issues
in neighboring RC Areas. This Wide Area purview provides continuity in the review process and
facilitates the evaluation of interactions among separate RAS as well as interactions among the
RAS and other protection and control systems. The selection of the RC also minimizes the
possibility of a “conflict of interest” that could exist because of business relationships among
the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP), or other entities that are
likely to be involved in the planning or implementation of a RAS. The RC may request assistance
in RAS reviews from other parties such as the PC(s) or regional technical groups (e.g., Regional
Entities); however, the RC retains responsibility for compliance with the requirement.
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each submitted RAS
for review. The time frame of four‐full‐calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
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Requirement R3
Requirement R3 mandates that the RAS‐entity address all issues identified by the reviewing RC
during the RAS review, and obtain approval from the reviewing RC that the RAS implementation
can proceed. The review by the RC is intended to identify reliability issues that must be resolved
before the RAS can be put in service. Examples of reliability issues include a lack of
dependability, security, or coordination.
Dependability is a component of reliability and is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over‐tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability and is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re‐configuring the System. Such actions, if inadvertently taken, are undesirable
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC‐
012‐2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS‐entity (and any other RAS‐owner) or
the reviewing RC(s) may have alternative ideas or methods available to resolve the issue(s). In
either case, the concern needs to be resolved in deference to reliability, and the RC has the final
decision.
A specific time period for the RAS‐entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS‐owner to effect a timely
implementation.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every 60‐
full‐calendar months. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in system topology or operating
conditions that have occurred since the previous RAS evaluation (or initial review) may change
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the effectiveness of a RAS or the way it interacts with and impacts the BES.
A period of sixty‐full‐calendar months was selected as the maximum time frame between
evaluations based on similar requirements in NERC Reliability Standards PRC‐006, PRC‐010, and
PRC‐014. The RAS evaluation should be performed sooner if it is determined that material
changes to System topology or System operating conditions that could potentially impact the
effectiveness or coordination of the RAS have occurred since the previous RAS evaluation or will
occur before the next scheduled evaluation. The periodic RAS evaluation will lead to one of the
following outcomes: 1) affirmation that the existing RAS is effective; 2) identification of changes
needed to the existing RAS; or 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1 through 4.4)
are planning analyses that involve modeling of the interconnected transmission system to
assess BES performance; consequently, the TP is the functional entity best suited to perform
the analyses. To promote reliability, the TP is required to provide the RAS‐owner(s) and the
reviewing RC(s) with the results of each evaluation.
The intent of Requirement R4, Part 4.3 is to require that the possible inadvertent operation of
the RAS, caused by the malfunction of a single component of the RAS, meet the same System
performance requirements as those required for the Contingency(ies) or System conditions for
which it is designed. If the RAS is designed to meet one of the planning events (P0‐P7) in TPL‐
001‐4, the possible inadvertent operation of the RAS must meet the same performance
requirements listed in the standard for that planning event. The requirement clarifies that the
inadvertent operation to be considered is only that caused by the malfunction of a single RAS
component. This allows features to be designed into the RAS to improve security, such that
inadvertent operation due to malfunction of a single component is prevented or else the RAS
inadvertent operation satisfies Requirement R4, Part 4.3.
The intent of Requirement R4, Part 4.3 is also to require that the possible inadvertent operation
of the RAS installed for an extreme event in TPL‐001‐4 or for some other Contingency or System
conditions not defined in TPL‐001‐4 (therefore without performance requirements), meet the
minimum System performance requirements of Category P7 in Table 1 of NERC Reliability
Standard TPL‐001‐4. However, instead of referring to the TPL standard, the requirement lists
the System performance requirements that a potential inadvertent operation must satisfy. The
performance requirements listed (Requirement R4, Parts 4.3.1 – 4.3.5) are the ones that are
common to all planning events P0‐P7 listed in TPL‐001‐4.
With reference to Requirement 4, Part 4.3, note that the only differences in performance
requirements among the TPL P0‐P7 events (not common to all of them) concern Non‐
Consequential Load Loss and interruption of Firm Transmission Service. Performance
requirements in these areas are not relevant. A RAS is only allowed to drop non‐consequential
load or interrupt Firm Transmission Service can do that only if that action is allowed for the
Contingency for which it is designed. Therefore, the inadvertent operation should automatically
meet Non‐Consequential Load Loss or interrupting Firm Transmission Service performance
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requirements for the Contingency(ies) for which it was designed.
Part 4.4 requires that a single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance requirements (defined
in Reliability Standard TPL‐001‐4 or its successor) as those required for the events and
conditions for which the RAS is designed. This analysis is needed to ensure that changing
System conditions do not result in the single component failure requirement not being met.
Requirements for inadvertent RAS operation (Requirement R4, Part 4.3) and single component
failure (Requirement R4, Part 4.4) are reviewed by the reviewing RC(s) before a new or
functionally modified RAS is placed in service, and are typically satisfied by specific design
considerations. Although the scope of the periodic evaluation does not include a new design
review, it is possible that a design which previously satisfied requirements for inadvertent RAS
operation and single component failure may fail to satisfy these requirements at a later point in
time, and must be evaluated with respect to the current System. For example, if the actions of a
particular RAS include tripping load, System changes could occur over time that impact the
amount of load originally tripped by a particular RAS output. These changes could result in
inadvertent activation of that output, therefore, tripping too much load and result in violations
of Facility Ratings. Alternatively, the RAS might be designed to trip more load than necessary
(i.e., “over trip”) in order to satisfy single‐component‐failure requirements. System changes
could result in too little load being tripped at affected locations and result in unacceptable BES
performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiency(ies) that manifested in
the incorrect RAS operation or failure of RAS to operate when expected.
The 120‐calendar day time frame for the completion of RAS operational performance analysis
aligns with the time frame established in Requirement R1 from PRC‐004‐4 regarding the
investigation of a Protection System Misoperation. To promote reliability, the RAS‐owner(s) is
required to provide the results of RAS operational performance analyses to its reviewing RC(s).
The RAS‐owner(s) may need to collaborate with their associated TP to comprehensively analyze
RAS operational performance. This is because a RAS operational performance analysis involves
verifying that the RAS operation triggers and responds (Parts 5.1, 5.2) and that the resulting BES
response (Parts 5.3, 5.4) is consistent with the intended functionality and design of the RAS.
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Requirement R6
Deficiencies identified either in the periodic RAS evaluation conducted by the TP in
Requirement R4, or in the analysis conducted by the RAS‐owner(s) pursuant to Requirement
R5, are likely to pose a reliability risk to the BES. To mitigate this reliability risk, Requirement R6
mandates that each RAS‐owner develop a CAP that establishes the mitigation actions and
timetable to address the deficiency. If the CAP requires that a functional change be made to a
RAS, Attachment 1 information must be submitted to the reviewing RC(s) prior to placing RAS
modifications in service per Requirement R1.
Depending on the complexity of the issues, development of a CAP may require study,
engineering, or consulting work. A timeframe of six‐full‐calendar months is allotted to allow
enough time for RAS‐owner collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. A RAS deficiency may require the RC or
Transmission Operator to impose operating restrictions so the System can operate in a reliable
way until the RAS deficiency is resolved. Such operating restrictions will incent the RAS‐owner
to resolve the issue as quickly as possible.
A CAP documents a RAS performance deficiency, the actions to correct the deficiency with
identified tasks, and the time frame for completion.
The following are example situations of when a CAP is required:
A determination after a RAS operation/non‐operation investigation that the RAS did not
meet performance expectations. The RAS did not operate as designed.
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
Equipment failures.
Requirement R7
Implementation of a CAP ensures that RAS deficiencies are corrected by following a
documented timetable of identified actions. If necessary, the CAP can be modified to account
for adjustments to the actions or scheduled timetable of activities. Operating restrictions
imposed by the RC also incents RAS‐owners to mitigate the issues and provide assurance that
implementation is completed in a timely manner.
Requirement R8
The reliability objective of Requirement R8 is to test the non‐Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and within the expected time using the in‐service settings and logic. Functional testing
is aimed at assuring overall RAS performance and not the component focused testing contained
in the PRC‐005 maintenance standard.
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Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed without impact to the BES
and should align with expected results. The RAS‐owner is in the best position to determine the
testing procedure and schedule due to their overall knowledge of the RAS design, installation,
and functionality. Periodic testing provides the RAS‐owner assurance that latent failures may be
identified and also promotes identification of changes in the System that may have introduced
latent failures.
While the six‐calendar‐year functional testing interval is greater than the annual or bi‐annual
periodic testing performed in some NERC Regions, the drafting team selected it because it is
consistent with some of the maintenance intervals of various Protection System and Automatic
Reclosing components established in PRC‐005. Consequently, this interval provides entities the
opportunity to design their RAS functional testing programs such that it coincides with the
testing of any associated PRC‐005 components. The six‐calendar‐year interval is a balance
between the resources required to perform the testing and the potential reliability impacts to
the BES created by undiscovered latent failures that could cause an incorrect operation of the
RAS.
Functional testing is not synonymous with end‐to‐end testing. End‐to‐end testing is acceptable
but it may not feasible for many RAS. When end‐to‐end testing is not possible, a RAS‐owner
may use a segmented functional testing approach. The segments can be tested individually
negating the need for complex maintenance schedules. In addition, actual RAS operation(s) can
be used to fulfill the functional testing requirement. If a RAS does not operate in its entirety
during a System event or System conditions do not allow an end‐to‐end system test—the, the
segmented approach should be used to fulfill this Requirement. Functional testing includes the
testing of all RAS inputs used for detection, arming, operating, and data collection. Functional
testing also includes the processing by the logic and infrastructure of a RAS as well as the action
initiation by RAS outputs to address the System condition(s) for which the RAS is designed. All
segments and components of a RAS must be tested or have proven operations within a six‐
calendar‐year interval to demonstrate compliance with the Requirement.
As an example, consider a RAS implemented with one PLC that senses System conditions such
as loading and line status from many locations. At one of these locations, a line protective relay
(a component of a Protection System and included in the Protection System Maintenance
Program (PSMP) of a RAS‐owner) receives commands from the RAS PLC and sends data over
non‐Protection System communications infrastructure to operate a breaker. A functional test
would send signals of simulated System conditions to the PLC to initiate an operate command
to the protective relay, thus operating its associated breaker. This action verifies RAS action,
verifies PLC control logic, and verifies RAS communications from PLC to relay. To complete this
portion of a functional test, application of external testing signals to the protective relay,
verified at the PLC are necessary to confirm full functioning of the RAS segment being tested.
This example describes a test for one segment of the RAS, the remaining segments would also
require testing.
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IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3‐8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well‐defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component‐level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real‐time) to
the Transmission Operator via PRC‐001, Requirement R6, then to the RC via TOP‐001‐2,
Requirement R5. Consequently, it is not necessary to include a similar requirement in this
standard.
Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available to entities with a potential reliability need. Attachment 3
contains the minimum information that is required to be included about each RAS listed in the
database. Additional information can be requested by the RC.
The information provided is sufficient for an entity with a reliability need to evaluate whether
the RAS can impact its System. For example, a RAS performing generation rejection to mitigate
an overload on a transmission line may cause a power flow change within an adjacent entity
area. This entity should be able to evaluate the risk that a RAS poses to its System from the
high‐level information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS‐entity from the RC.
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The following diagrams depict the process flow of the PRC‐012‐2 requirements.
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS‐owner(s) to provide a detailed list of information
describing the RAS to the designated RAS‐entity. If there are multiple owners of the RAS,
information may be needed from all owners, but a single RAS‐owner (designated as the RAS‐
entity) is assigned the responsibility of compiling the RAS data and presenting it to the
reviewing RC(s). Other RAS‐owners may participate in the review, if they choose.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide‐ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified3 RAS that the RAS‐entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS‐entity
provides a summary of the previously approved RAS functionality.
I.
General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single‐line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3Functionally Modified: Any modification to a RAS beyond the replacement of components that preserve the original
functionality is a functional modification.
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3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012‐2, Requirements R5 and R7]
Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, or the analysis of an actual RAS operation
pursuant to Requirement R5. A copy of the most recent CAP must be submitted in
addition to the other data specified in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name
b. RAS‐entity and contact information
c. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date;
most recent 60‐full‐calendar‐month (Requirement R4) evaluation date; and, date of
retirement, if applicable
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery)
e. Description of the contingencies or System conditions for which the RAS was
designed (initiating conditions)
f. Corrective action taken by the RAS
g. Any additional explanation relevant to high level understanding of the RAS
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II.
Functional Description and Transmission Planning Information
1. Contingencies and system conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical system
contingencies or other operating conditions when RAS action is intended to occur. If
no arming conditions are required, this should also be stated.
c. Event‐based RAS are triggered by specific contingencies that initiate mitigating
action. Condition‐based RAS may also be initiated by specific contingencies, but
specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
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2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), system conditions, and contingencies
analyzed on which the RAS design is based, and when those technical studies were
performed. [Reference NEC Reliability Standard PRC‐014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS‐related operations.
4. Information regarding any future system plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. Documentation showing that the possible inadvertent operation of the RAS resulting
from any single RAS component malfunction satisfies all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
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6. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or re‐
configuring the system. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available fault duty,
which can affect distance relay overcurrent (“fault detector”) supervision and ground
overcurrent protection coordination.
7. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection,
telecommunications, transfer trip, logic processing, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be designed
to be secure. Several types of devices have been commonly used as disturbance, condition,
or status detectors:
Line open status (event detectors),
Protective relay inputs and outputs (event and parameter detectors),
Transducer and IED (analog) inputs (parameter and response detectors),
Rate of change (parameter and response detectors).
Telecommunications Channels and Transfer Trip Equipment
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non‐deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel or
equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS‐owner, or
perhaps leased from another entity familiar with the necessary reliability requirements. All
channel equipment should be monitored and alarmed to the dispatch center so that timely
diagnostic and repair action shall take place upon failure. Publicly switched telephone
networks are generally an undesirable option.
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Communication channels should be well labeled or identified so that the personnel working
on the channel can readily identify the proper circuit. Channels between entities should be
identified with a common name at all terminals.
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions may
be required at different arming levels or for different contingencies. Scheme logic may be
achievable by something as simple as wiring a few auxiliary relay contacts or by much more
complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units (RTUs),
and logic processors. Single‐function relays have been used historically to implement RAS,
but this approach is now less common except for very simple new RAS or minor additions to
existing RAS.
Monitoring by SCADA/EMS should include at least
Whether the scheme is in‐service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in‐service or out of service.
For RAS that are armed automatically, these two states are independent because a
RAS that has been placed in service may be armed or unarmed based on whether
the automatic arming criteria have been met.
The current operational state of the scheme (available or not).
In cases where the RAS requires single‐component failure performance (redundancy),
the minimal status indications should be provided separately for each system.
The minimum status is generally sufficient for operational purposes; however,
where possible it may be useful to provide additional information regarding partial
failures or the status of critical components to allow the RAS‐owner to more
efficiently troubleshoot a reported failure. Whether this capability exists will depend
in part on the design and vintage of equipment used in the RAS. While all schemes
should provide the minimum level of monitoring, new schemes should be designed
with the objective of providing monitoring at least similar to what is provided for
microprocessor‐based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
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Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line‐charging current;
c. Breaker trip coil current monitoring—typically used when high‐speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of these,
out of step, etc.—very dependent on specific scheme requirements, but some forms
may substitute for or enhance current monitoring detection.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in service or is being
maintained.
In this context, a multifunction device (e.g., microprocessor‐based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor‐based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi‐function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
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Supplemental Material
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation showing that a single‐component failure in a RAS, when the RAS is
intended to operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. The
documentation should describe or illustrate how the implementation design achieves
this objective. [Reference NERC Reliability Standard PRC‐012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement.
Acceptable methods to achieve this objective include the following:
a. Providing redundancy of RAS components listed below:
i.
Protective or auxiliary relays used by the RAS.
ii.
Communications systems necessary for correct operation of the RAS.
iii.
Sensing devices used to measure electrical quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Computers or programmable logic devices used to analyze information and
provide RAS operational output.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation would not be an issue, if tripping the total armed
amount of load or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re‐dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
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Supplemental Material
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS‐entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies, if applicable, upon which the decision to retire the RAS
is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Supplemental Material
Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to assist the RC in identifying reliability considerations
generally relevant to aspects of RAS design and implementation, and also for the purpose of
facilitating consistent reviews continent‐wide for each RAS to be installed or functionally
modified. Most of the checklist items should be applicable to most RAS. There may be
checklist items that are not applicable to a given RAS in which case they may be noted as not
applicable and skipped in the RC review. Depending on the specifics of the RAS under review, it
is possible that other reliability considerations may be identified during the review. Any other
reliability considerations, along with their resolution with respect to the particular RAS under
review, should be documented along with the Attachment 2 items that were applicable to the
specific RAS under review.
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Supplemental Material
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
The name used to identify the RAS.
2. RAS‐entity and contact information.
A reliable phone number or email address should be included to contact the RAS‐entity
if more information is needed. At a minimum, the name of the RAS‐entity responsible
for the RAS information should be provided.
3. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date; most
recent 60‐full‐calendar‐month (Requirement R4) evaluation date; and, date of retirement, if
applicable.
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under‐/over‐voltage, slow voltage
recovery).
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the contingencies or System conditions for which the RAS was designed
(initiating conditions).
A high level summary of the conditions/contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
7. Any additional explanation relevant to high‐level understanding of the RAS.
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
Draft 1 of PRC‐012‐2
August 2015
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Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
PRC‐012‐2 – Remedial Action Schemes
Requested Retirements of Reliability Standards1
PRC‐012‐0 – Special Protection System Review Procedure
PRC‐013‐0 – Special Protection System Database
PRC‐014‐0 – Special Protection System Assessment
PRC‐012‐1 – Special Protection System Review Procedure
PRC‐013‐1 – Special Protection System Database
PRC‐014‐1 – Special Protection System Assessment
PRC‐015‐0 – Special Protection System Data and Documentation
PRC‐016‐0.1 – Special Protection System Misoperations
PRC‐015‐1 – Special Protection System Data and Documentation
PRC‐016‐1 – Special Protection System Misoperations
Prerequisite Approval
Revised definition of “Remedial Action Scheme”
Applicable Entities
Reliability Coordinator
Transmission Planner
RAS‐owner – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part
of a RAS
RAS‐entity – the RAS‐owner designated to represent all RAS‐owner(s) for coordinating the review and
approval of a RAS
1
Retirement includes withdrawal of pending Reliability Standards.
General Considerations
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for RAS and
associated revisions to related Reliability Standards to consolidate that term with the Glossary term
“Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not enforceable,
NERC revised these standards to account for the RAS definition revision and changed relevant version
numbers to reflect the change. Because of this change, NERC requested retirement of PRC‐012‐0, PRC‐
013‐0, and PRC‐014‐0, and provided, for informational purposes only, updated Reliability Standards PRC‐
012‐1, PRC‐013‐1, and PRC‐014‐1. In the same Petition, NERC requested approval of Reliability Standards
PRC‐015‐1 and PRC‐016‐1 and retirement of PRC‐015‐0 and PRC‐016‐0.1, again implementing changes
stemming from the revised definition of RAS.
The Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept the revisions on
June 18, 2015. As of the date of posting of this Implementation Plan, however, the Commission has not
issued an Final Order approving and retirement the Reliability Standards enumerated above. Because the
standard drafting team for this project has determined that the retirements requested above are
necessary to ensure a seamless transition to consolidation of these standards in PRC‐012‐2, NERC
reiterates the requests for retirements already submitted in the Petition and those that are still pending
at the Commission.
Effective Dates for PRC-012-2
The proposed Reliability Standard PRC‐012‐2 shall become effective on the later of the day after the
revised definition of Remedial Acton Scheme becomes effective or the first day of the first calendar
quarter that is twelve (12) months after the date the standard is approved by an applicable governmental
authority or as otherwise provided for in a jurisdiction where approval by an applicable governmental
authority is required for a standard to go into effect. Where approval by an applicable governmental
authority is not required, the standard shall become effective on the first day of the first calendar quarter
that is twelve (12) months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the Effective Date of PRC‐
012‐2 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
August 2015
Page 2 of 2
Unofficial Comment Form
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
DO NOT use this form for submitting comments. Use the electronic form to submit comments on draft 1
of PRC-012-2 – Remedial Action Schemes. The electronic comment form must be submitted by 8 p.m.
Eastern, Monday, October 5, 2015.
Documents and information about this project are available on the project page. If you have questions,
contact Standards Developer, Al McMeekin (via email), or at (404) 446-9675.
Background Information
This project is addressing all aspects of Remedial Action Schemes (RAS) and Special Protection Systems
(SPS) contained in the RAS/SPS-related Reliability Standards: PRC-012-1, PRC-013-1, PRC-014-1, PRC-0151, and PRC-016-1. The maintenance of the Protection System components associated with RAS (PRC-0171 Remedial Action Scheme Maintenance and Testing) are already addressed in PRC-005. PRC-012-2
addresses the testing of the non-Protection System components associated with RAS/SPS
In FERC Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and
PRC-014-0 as “fill-in-the-blank” standards and did not approve or remand them. These standards are
applicable to the Regional Reliability Organizations (RROs), assigning the RROs the responsibility to
establish regional procedures and databases, and to assess and document the operation, coordination,
and compliance of RAS/SPS. The deference to regional practices precludes the consistent application of
RAS/SPS-related Reliability Standard requirements.
The proposed draft of PRC-012-2 corrects the applicability of the fill-in-the-blank standards by assigning
the requirement responsibilities to the specific users, owners, and operators of the Bulk-Power System;
and incorporates the reliability objectives of all the RAS/SPS-related standards.
45-day Formal Comment Period
The drafting team is soliciting stakeholder comments and feedback on the first draft of PRC-012-2. The
team appreciates the feedback you provided during the informal comment period earlier this year and
considered all of your suggestions. While many of your thoughts were incorporated into this product, a
few were not and the drafting team offers the following explanations.
Choice of applicable entity in specific requirements: The drafting team selected the functional entity they
assert is the most capable of performing the required actions. The drafting team recognizes that in some
instances the specified entity will need to collaborate with or obtain information from other entities. For
example, in Requirement R5, the RAS-owner is tasked with analyzing RAS operations. The RAS-owner was
designated because they own the RAS and are responsible for maintaining the performance of the RAS.
The drafting team recognizes that the RAS-owner may need to obtain information from entities such as
the Transmission Operator, Transmission Planner, Balancing Authority, or others to complete the analysis
but contends that ultimate responsibility should remain with the RAS-owner.
Periodic Planning Evaluation Considerations: Requirement R4 mandates that the Transmission Planner
(TP) perform a technical evaluation (planning analyses) of each RAS at least once every 60 full calendar
months to verify the continued effectiveness and coordination of the RAS, including BES performance
following an inadvertent operation and single component failure of the RAS.
In structuring Requirement R4, the SDT considered the issue of the TP reviewing the RAS design made by
the RAS-owner. Although the TP is not involved in the detailed design of the RAS, the SDT asserts that the
TP is aware, to some extent, of the redundancy level of the RAS design from the initial planning studies.
Requirement R4 is a planning evaluation to assess the impact of System changes over time on the RAS
effectiveness and is not intended to be a RAS design review.
The language used in the current Requirement R4, Part 4.4 is aligned with the language of Requirement
R1.3 in PRC-012-0 (RAS single component failure).The evaluation of a RAS under Requirement R4, Part 4.4
will consider the following three scenarios:
1. The RAS was originally designed such that a “single component failure” does not prevent RAS
operation in-whole. Due to System changes that may affect achieving the System performance
requirement(s), the TP must re-evaluate whether the operation of the RAS still meets them. If it
does not, then a CAP must be developed per Requirement R6 to meet “single component failure”
performance requirements.
2. The RAS was originally designed such that a “single component failure” could cause the RAS to not
operate when intended. Therefore, System performance when the RAS fails to operate must be
evaluated. For deficient System performance, a CAP must be developed per Requirement R6 to
meet “single component failure” performance requirements.
3. The RAS was designed such that a “single component failure” could cause part but not all of the
RAS to not operate, yet still meet the System performance requirement(s) (e.g. over-arming used
to mitigate “single component failure” for load shedding or generation rejection). Due to System
changes that may affect achieving the System performance requirement(s), the TP must reevaluate whether partial operation of the RAS still meets them. If it does not, then a CAP must be
developed per Requirement R6 to meet “single component failure” performance requirements.
In all cases, detailed design review is not required. The SDT recognizes that involvement of the RAS-owner
may be necessary for the TP to be aware of the consequences of single component failure for its RAS.
Unofficial Comment Form | PRC-012-2 Draft 1
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2
CAP Development Considerations: The drafting team selected the RAS-owner as the applicable entity to
develop, submit, and implement CAPs associated with RAS performance because they own the RAS, are
responsible for maintaining the performance of the RAS, and make all of the financial decisions regarding
the RAS. The six-month timeframe to develop a CAP was selected to provide enough time for engineering
studies to analyze possible modifications to the RAS. The six months is the maximum timeframe. The SDT
anticipates that most CAPs can be developed in less time. The glossary definition of a CAP includes the
work schedules associated with implementing and completing actions within the CAP. The
implementation timeframe should not impact System reliability because the RC will determine whether
the RAS can remain in service, or if other System operating limits must be imposed. The RAS-owner must
submit the CAP to the RC. The RC is not required to approve a CAP that does not require functional
modifications to the RAS; however, the drafting team expects the RC would provide feedback on any
concerns with CAP adequacy. A CAP that does require functional modifications will be reviewed and
approved by the RC in accordance with Requirements R1, R2, and R3.
Functional Testing: The drafting team asserts that the functional testing of RAS should remain in PRC-0122 and not be included in PRC-005.While the drafting team agrees that many RAS have Protection System
components that will be maintained in accordance with PRC-005, the purpose of the functional testing is
to verify the control equipment operation and confirm the overall RAS performance rather than the
performance of individual Protection System components. PRC-005 does not include the maintenance of
RAS controllers such as PLCs, computers, or the control functions of microprocessor relays. There is no
double jeopardy because PRC-012-2 specifically requires the verification of only non-Protection System
components. The drafting team contends that functional testing is complementary to the Protection
System component maintenance required in PRC-005. An entity could maintain its Protection System
components in association with a functional testing of a RAS and document it for compliance with its
Protection System Maintenance Plan for PRC-005.
RAS Database and Attachment 3: The drafting team selected the Reliability Coordinator to maintain the
RAS database because the RC is the reviewing entity for new and functionally modified RAS and as such
receives the pertinent data from the RAS-entity in Attachment 1. The RAS database serves as a repository
of information about all RAS in an RC Area that enables entities with a reliability-related need access to the
information through the RC. The data in Attachment 3 is the minimum an RC is required to maintain;
however, the RC has the discretion to require additional information deemed necessary for a high-level
understanding of a RAS. The drafting team contends it is not necessary to require detailed information for
every RAS in the database as that would make database maintenance a burden for both the RC and the
entities, while bringing little improvement to reliability. While the SDT agrees that detailed information may
be important to an entity with a reliability-related need, it was agreed that such cases are specific enough
to be treated individually and not systematically through a standard requirement. The drafting team also
asserts that a requirement for an entity to provide detailed modeling information to other registered
entities is not necessary. Entities that have a reliability-related need for this information have multiple
avenues to get the data; e.g., regional model building processes, Planning Coordinator, and/or direct
request to the RAS-owner.
Unofficial Comment Form | PRC-012-2 Draft 1
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3
The drafting team is charged with assigning the requirements of the new standard to the specific users,
owners, and operators of the Bulk-Power System while incorporating the reliability objectives of all the
RAS/SPS-related standards. In drafting this standard, the team has worked diligently to minimize the
changes that will be required from your existing processes. The drafting team requests that you read the
standard including the rationales and technical justifications thoroughly and provide your thoughtful
comments. The electronic comment form must be completed by 8 p.m. Eastern Monday, October 5,
2015.
Questions
Requirements R1, R2, and R3 pertain to the submittal of Attachment 1 information to the Reliability
Coordinator (RC) for the review of a RAS, the RC using Attachment 2 as a guide for performing the RAS
review, and the RC approving the RAS prior to the RAS being placed in service. Question 1 is relevant to
these activities.
1. RAS review and approval: Do you agree with the RAS review process outlined by Requirements R1,
R2, and R3? If no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
Requirement R4 mandates that the Transmission Planner perform a technical evaluation (planning
analyses) of each RAS at least once every 60 full calendar months to verify the continued effectiveness
and coordination of the RAS, including BES performance following an inadvertent operation and single
component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
2. RAS Periodic Evaluations: Do you agree with the RAS planning evaluation process outlined by
Requirement R4? If no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
3. RAS Inadvertent Operation: Do you agree with Requirement 4 Part 4.3 and Attachment 1 which
stipulates that RAS inadvertent operation due to a single component malfunction still satisfies the
System performance requirements common to TPL-001-4 P1-P7 events listed in Parts 4.3.1-4.3.5?
(Note that this requirement remains the same as PRC-012-0 R1.4 except for the allowance for
designed-in security that would prevent RAS inadvertent operation for any single component
malfunction). If no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Unofficial Comment Form | PRC-012-2 Draft 1
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4
Comments:
4. RAS Single Component Failure: Do you agree with Requirement 4 Part 4.4 and Attachment 1 which
stipulates that any RAS intended to satisfy System performance requirements in a TPL standard must
still satisfy those requirements when experiencing a single component failure? (Note that this
requirement remains unchanged from PRC-012-0 R1.3.) If no, please provide the basis for your
disagreement and an alternate proposal.
Yes
No
Comments:
Requirements R6 and R7 pertain to the development and implementation of Corrective Action Plans
(CAPs). Question 5 addresses these requirements.
5. Corrective Action Plans: Do you agree that the application of Requirements R6 and R7 would address
the reliability objectives associated with CAPs? If no, please provide the basis for your disagreement
and an alternate proposal.
Yes
No
Comments:
6. Implementation Plan: Do you agree with the Implementation Plan? If no, please provide the basis for
your disagreement and an alternate proposal.
Yes
No
Comments:
7. If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Comments:
Unofficial Comment Form | PRC-012-2 Draft 1
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5
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
Translation to New
Standard or Other Action
PRC‐012‐1 R.1.1:
Covered by Requirements R1,
R2 and R3.
PRC‐012‐1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC‐012‐1 R.1.3:
R1.1. Description of the process for submitting a
Covered by Requirement R1,
proposed RAS for Regional Reliability
Attachments 1, Requirement
Organization review.
R2, Attachment 2 and
R1.2. Requirements to provide data that describes Requirement R4.4
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
PRC‐012‐1 R.1.4:
shall be designed so that a single RAS
Covered by Requirement R1,
component failure, when the RAS was
Attachments 1, Requirement
intended to operate, does not prevent the
R2, Attachment 2, and
interconnected transmission system from
Requirement R4.3.
meeting the performance requirements
defined in Reliability Standards TPL‐001‐0,
TPL‐002‐0, and TPL‐003‐0.
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity shall
submit the information identified in Attachment 1 for
review to the Reliability Coordinator(s) that coordinates
the area(s) where the RAS is located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to the RAS‐entity.
R3. Following the review performed pursuant to
Requirement R2, the RAS‐entity shall address each
identified issue and obtain approval from each reviewing
Reliability Coordinator, prior to placing a new or
functionally modified RAS in service or retiring an existing
RAS.
R4. Each Transmission Planner shall perform an
evaluation of each RAS within its planning area at least
once every 60 full calendar months and provide the RAS‐
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
PRC‐012‐1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4.2.
PRC‐012‐1 R.1.6:
R1.5. Requirements to demonstrate the proposed Covered by Requirement R5
RAS will coordinate with other protection
and control systems and applicable Regional PRC‐012‐1 R.1.7:
Reliability Organization Emergency
Covered by Requirements R4
procedures.
and R6
R1.6. Regional Reliability Organization definition
PRC‐012‐1 R.1.8:
of misoperation.
PRC‐012‐2 NERC Standards
R1.7. Requirements for analysis and
Development Process
documentation of corrective action plans for
all RAS misoperations.
PRC‐012‐1 R.1.9:
Covered by Requirement R8
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL‐
001‐0, TPL‐002‐0, and TPL‐003‐0) as that
required of the contingency for which it was
designed, and not exceed TPL‐003‐0.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
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New or revised Requirement in Proposed
Reliability Standard PRC-012-2
owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each
evaluation shall determine whether:
4.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.2 The RAS avoids adverse interactions with
other RAS, and protection and control systems
4.3 The possible inadvertent operation of the RAS
resulting from any single RAS component
malfunction satisfies all of the following:
4.3.1 The BES shall remain stable.
4.3.2 Cascading shall not occur.
4.3.3 Applicable Facility Ratings shall not
be exceeded.
4.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
established by the Transmission Planner
and the Planning Coordinator.
4.3.5 Transient voltage responses shall be
within acceptable limits as established by
the Transmission Planner and the Planning
Coordinator.
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.4 A single component failure in the RAS, when
the RAS is intended to operate, does not prevent
the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐
001‐4 or its successor) as those required for the
events and conditions for which the RAS is
designed.
R5. Each RAS‐owner shall, within 120‐calendar days of a
RAS operation or failure of a RAS to operate when
expected, analyze the RAS performance and provide the
results of the analysis, including any identified
deficiencies, to its reviewing Reliability Coordinator(s).
The RAS operational performance analysis shall
determine whether:
5.1 The System events and/or conditions
appropriately triggered the RAS.
5.2 The RAS responded as designed.
5.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.4 The RAS operation resulted in any unintended
or adverse BES response.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐owner shall participate in
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Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
developing a Corrective Action Plan (CAP) and submit the
CAP to its reviewing Reliability Coordinator(s).
R8. At least once every six calendar years, each RAS‐
owner shall perform a functional test of each RAS to
verify the overall RAS performance and the proper
operation of non‐Protection System components.
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and
NERC with documentation of its RAS review
procedure on request (within 30 calendar days).
Retired P81
N/A
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4
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
PRC‐013‐1 R1:
Covered by Requirement R9
PRC‐013‐1 R1.1:
Covered by Requirement R9,
Attachment 3
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
PRC‐013‐1 R1.2:
designed,
Covered by Requirement R9,
R1.2. Operation — The actions taken by the RAS in Attachment 3
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic PRC‐013‐1 R1.3:
Covered by Requirement R9,
or relay settings that control operation of
Attachment 3
the RAS.
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
R2. The Regional Reliability Organization shall provide
to affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once each calendar year.
N/A
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Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
PRC‐014‐1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Transmission Planner shall perform an
evaluation of each RAS within its planning area at least
once every 60 full calendar months and provide the RAS‐
owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each
evaluation shall determine whether:
4.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.2 The RAS avoids adverse interactions with
other RAS, and protection and control systems.
4.3 The possible inadvertent operation of the RAS
resulting from any single RAS component
malfunction satisfies all of the following:
4.3.1 The BES shall remain stable.
4.3.2 Cascading shall not occur.
4.3.3 Applicable Facility Ratings shall not
be exceeded.
4.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
established by the Transmission Planner
and the Planning Coordinator.
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Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.3.5 Transient voltage responses shall be
within acceptable limits as established by
the Transmission Planner and the Planning
Coordinator.
4.4 A single component failure in the RAS, when
the RAS is intended to operate, does not prevent
the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐
001‐4 or its successor) as those required for the
events and conditions for which the RAS is
designed.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
PRC‐014‐1 R2:
Covered by Requirement R4
R4. Each Transmission Planner shall perform an
evaluation of each RAS within its planning area at least
once every 60 full calendar months and provide the RAS‐
owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each
evaluation shall determine whether:
4.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.2 The RAS avoids adverse interactions with
other RAS, and protection and control
systems.
4.3 The possible inadvertent operation of the RAS
resulting from any single RAS component
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Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
inadvertent operation satisfies all of the
following:
4.3.1 The BES shall remain stable.
4.3.2 Cascading shall not occur.
4.3.3 Applicable Facility Ratings shall not
be exceeded.
4.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage
deviation limits as established by the
Transmission Planner and the Planning
Coordinator.
4.3.5 Transient voltage responses shall be
within acceptable limits as established by
the Transmission Planner and the Planning
Coordinator.
4.4 A single component failure in the RAS, when
the RAS is intended to operate, does not prevent
the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐
001‐4 or its successor) as those required for the
events and conditions for which the RAS is
designed.
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Reliability Standard: PRC-014-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Transmission Planner shall perform an
evaluation of each RAS within its planning area at least
once every 60 full calendar months and provide the RAS‐
owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each
evaluation shall determine whether:
R3.2. Study years, system conditions, and
contingencies analyzed in the technical
studies on which the assessment is based
and when those technical studies were
performed.
PRC‐014‐1 R2:
Covered by Requirement R4
PRC‐014‐1 R3.1:
Covered by Requirement R4
PRC‐014‐1 R3.2:
Covered by Requirement R4
PRC‐014‐1 R3.3:
Covered by Requirement R4
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
PRC‐014‐1 R3.4:
Covered by Requirement R4
R3.4. Discussion of any coordination problems
found between a RAS and other protection
and control systems.
PRC‐014‐1 R3.5:
Covered by Requirement R6
Existing Requirement in Reliability Standard
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
R3.1. Identification of group conducting the
assessment and the date the assessment
was performed.
R3.5. Provide corrective action plans for non‐
compliant RAS.
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4.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.2 The RAS avoids adverse interactions with
other RAS, and protection and control systems.
4.3 The possible inadvertent operation of the RAS
resulting from any single RAS component
inadvertent operation
satisfies all of the following:
4.3.1 The BES shall remain stable.
4.3.2 Cascading shall not occur.
4.3.3 Applicable Facility Ratings shall not
be exceeded.
4.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
established by the Transmission Planner
and the Planning Coordinator.
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.3.5 Transient voltage responses shall be
within acceptable limits as established by
the Transmission Planner and the Planning
Coordinator.
4.4 A single component failure in the RAS, when
the RAS is intended to operate, does not prevent
the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐
001‐4 or its successor) as those required for the
events and conditions for which the RAS is
designed.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐owner shall participate in
developing a Corrective Action Plan (CAP) and submit the
CAP to its reviewing Reliability Coordinator(s).
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Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
PRC‐015‐1 R1:
Distribution Provider that owns a RAS shall maintain Covered by Requirement R1,
a list of and provide data for existing and proposed Attachment 1.
RAS as specified in Reliability Standard PRC‐013‐1
R1.
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity shall
submit the information identified in Attachment 1 for
review to the Reliability Coordinator(s) that coordinates
the area(s) where the RAS is located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC‐012‐1_R1 prior to being placed in
service.
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity shall
submit the information identified in Attachment 1 for
review to the Reliability Coordinator(s) that coordinates
the area(s) where the RAS is located.
PRC‐015‐1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to the RAS‐entity.
R3. Following the review performed pursuant to
Requirement R2, the RAS‐entity shall address each
identified issue and obtain approval from each reviewing
Reliability Coordinator, prior to placing a new or
functionally modified RAS in service or retiring an existing
RAS.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Retired P81
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N/A
11
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
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Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC‐012‐1_R1.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC‐016‐1 R1:
Covered by Requirement R5
R5. Each RAS‐owner shall, within 120‐calendar days of a
RAS operation or failure of a RAS to operate when
expected, analyze the RAS performance and provide the
results of the analysis, including any identified
deficiencies, to its reviewing Reliability Coordinator(s).
The RAS operational performance analysis shall
determine whether:
5.1 The System events and/or conditions
appropriately triggered the RAS.
5.2 The RAS responded as designed.
5.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.4 The RAS operation resulted in any unintended
or adverse BES response.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
PRC‐016‐1 R2:
Covered by Requirements R6
and R7.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐owner shall participate in
developing a Corrective Action Plan (CAP) and submit the
CAP to its reviewing Reliability Coordinator(s).
R7. For each CAP submitted pursuant to Requirement R6,
each RAS‐owner shall:
7.1 Implement the CAP.
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Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change.
R3. The Transmission Owner, Generator Owner, and
PRC‐016‐1 R3:
Distribution Provider that owns a RAS shall provide Covered by Requirements R5,
R6, and R7, Attachment 1.
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
R5. Each RAS‐owner shall, within 120‐calendar days of a
RAS operation or failure of a RAS to operate when
expected, analyze the RAS performance and provide the
results of the analysis, including any identified
deficiencies, to its reviewing Reliability Coordinator(s).
The RAS operational performance analysis shall
determine whether:
5.1 The System events and/or conditions
appropriately triggered the RAS.
5.2 The RAS responded as designed.
5.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.4 The RAS operation resulted in any unintended
or adverse BES response.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐owner shall participate in
developing a Corrective Action Plan (CAP) and submit the
CAP to its reviewing Reliability Coordinator(s).
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Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R7. For each CAP submitted pursuant to Requirement R6,
each RAS‐owner shall:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change.
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Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
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Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
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Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline (4) – 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.
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to submit
the information identified in
Attachment 1 to one or more of
the Reliability Coordinator(s) in
accordance with Requirement
R1.
7
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30‐calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30‐calendar days but
less than or equal to 60‐calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2 but was late by
more than 60‐calendar days but
less than or equal to 90‐calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90‐calendar days.
OR
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
11
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to obtain
approval from each reviewing
Reliability Coordinator prior to
placing a new or functionally
modified RAS in service or
retiring an existing RAS in
accordance with Requirement
R3.
N/A
15
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
The Transmission Planner
performed the evaluation in
accordance with Requirement
R4, in greater than 60‐full
calendar months but less than
or equal to 61‐full calendar
months.
Moderate
The Transmission Planner
performed the evaluation in
accordance with Requirement
R4, in greater than 61‐full
calendar months but less than
or equal to 62‐full calendar
months.
High
The Transmission Planner
performed the evaluation in
accordance with Requirement
R4, in greater than 62‐full
calendar months but less than
or equal to 63full calendar
months.
Severe
The Transmission Planner
performed the evaluation in
accordance with Requirement
R4, but in greater than 63‐full
calendar months.
OR
The Transmission Planner failed
to perform the evaluation in
accordance with Requirement
R4.
OR
The Transmission Planner
performed the evaluation in
accordance with Requirement
OR
R4, but failed to evaluate one of
The Transmission Planner
the Parts 4.1 through 4.4.
performed the evaluation in
accordance with Requirement
R4, but failed to evaluate two or
more of the Parts 4.1 through
4.4.
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
OR
The Transmission Planner
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
RAS‐owner(s) and the reviewing
Reliability Coordinator(s).
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
The RAS‐owner performed the
analysis in greater than 120‐
calendar days, but less than or
equal to 130‐calendar days in
accordance with Requirement
R5.
Moderate
The RAS‐owner performed the
analysis in greater than 130‐
calendar days, but less than or
equal to 140‐calendar days in
accordance with Requirement
R5.
High
The RAS‐owner performed the
analysis in greater than 140‐
calendar days, but less than or
equal to 150‐calendar days in
accordance with Requirement
R5.
OR
The RAS‐owner performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1
through 5.4.
Severe
The RAS‐owner performed the
analysis in greater than 150‐
calendar days.
OR
The RAS‐owner failed to
perform the analysis in
accordance with Requirement
R5.
OR
The RAS‐owner performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1 through 5.4.
OR
The RAS‐owner performed the
analysis in accordance with
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VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
Requirement R5, but failed to
provide the results to one or
more of the reviewing Reliability
Coordinator(s).
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10‐calendar days.
Moderate
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10‐calendar days but less than
or equal to 20‐calendar days.
High
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20‐calendar days but less than
or equal to 30‐calendar days.
Severe
The RAS‐owner developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30‐calendar days.
OR
The RAS‐owner developed a
Corrective Action Plan and failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐owner failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
The RAS‐owner implemented a
CAP (Part 7.1), but failed to
update the CAP (Part 7.2) if
actions or timetables changed
and failed to notify one or more
of the reviewing Reliability
Coordinator(s) (Part 7.3), in
accordance with Requirement
R7.
Moderate
N/A
High
N/A
Severe
The RAS‐owner failed to
implement a CAP (Part 7.1) in
accordance with Requirement
R7.
ifications for PRC‐012‐2, Requirement R7
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐owner performed the
functional test for a RAS as
specified in Requirement R8, but
was less than or equal to 30‐
calendar days late.
The RAS‐owner performed the
functional test for a RAS as
specified in Requirement R8, but
was more than 30‐calendar days
but less than or equal to 60‐
calendar days late.
The RAS‐owner performed the
functional test for a RAS as
specified in Requirement R8, but
was more than 60‐calendar days
but less than or equal to 90‐
calendar days late.
The RAS‐owner performed the
functional test for a RAS as
specified in Requirement R8, but
was more than 90‐calendar days
late.
OR
The RAS‐owner failed to
perform the functional test for a
RAS as specified in Requirement
R8.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VSLs for PRC‐012‐2, Requirement R9
Lower
Moderate
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30‐calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30‐calendar days but less than
or equal to 60‐calendar days.
High
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60‐calendar days but less than
or equal to 90‐calendar days.
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than
90‐calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
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FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
August 2015
Table of Contents
1. Why was the Reliability Coordinator chosen to perform the Remedial Action Scheme (RAS) review?
.............................................................................................................................................................................2
2. Why is the Planning Coordinator not required to perform an annual evaluation of RAS
performance?........................................................................................................................................ 2
3. Why is the five-year evaluation assigned to the Transmission Planner rather than the Reliability
Coordinator? ......................................................................................................................................... 3
4. Why do RAS need to be reviewed and approved by a group other than the RAS-owner? ................. 3
5. What is required for RAS “single component failure” and why is it required? .................................... 3
6. What is required for RAS inadvertent operation? ................................................................................ 4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and
control systems? ................................................................................................................................... 5
8. Why are RAS classifications not recognized in the standard? .............................................................. 5
9. What constitutes functional modification of a RAS? ............................................................................ 5
10. Why is the RAS-entity identified in the standard and what are its responsibilities? ........................... 6
Attachment A – Project Roster ..............................................................................................................................7
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Question & Answer | August 2015
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Question & Answer for PRC-012-2
The Project 2010-05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC-012-2.
1. Why was the Reliability Coordinator chosen to perform the
Remedial Action Scheme (RAS) review?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk-Power System. The NERC white paper suggested
Planning Coordinators (PCs) and Reliability Coordinators (RCs) for RAS-review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best-suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest-area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. This wide-area purview provides
continuity in the review process and better facilitates the evaluation of interactions among
separate RAS, as well as interactions among RAS and other protection and control systems. The
selection of the RC also minimizes the possibility of a conflict of interest that could exist because
of business relationships among the RAS-entity, PC, Transmission Planner (TP), or other entities
that are likely to be involved in the planning or implementation of a RAS. The RC is also less likely
to be a stakeholder in any given RAS and can therefore maintain objective independence.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2. Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP-005-1 Requirement R3 requires Balancing Authorities (BA) and Transmission Owners (TO) to
perform operational reliability assessments (e.g., real time contingency analysis (RTCA), dayahead, seasonal) that include data describing new or degraded RAS. In addition, IRO-005-1
Requirement R12 requires RCs to share any pertinent data, such as data from RAS, with
potentially affected BAs and TOs. Operating horizon assessments that include RAS are already
required by other standards, so an additional requirement duplicating that effort is not
necessary.
TPL-001-4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near-term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
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performance requirements. Short-term (annual) planning horizon assessments are already
required by the TPL-001-4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
3. Why is the five-year evaluation assigned to the Transmission
Planner rather than the Reliability Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least every 60 calendar
months to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, which is very similar to the planning analyses performed by
the TPs. The RC is more focused on actual System conditions, not necessarily on the conditions
for which a RAS was designed. The required evaluation is a detailed planning analysis and thus
the TP is better suited than the RC to perform the evaluation.
4. Why do RAS need to be reviewed and approved by a group other
than the RAS-owner?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to RAS-owners. An independent review and approval is an objective and effective
means of identifying risks and recommending RAS modifications when necessary.
5. What is required for RAS “single component failure” and why is it
required?
The existing PRC-012-1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.4 and
Attachment 1 of PRC-012-2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL-001-4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
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o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
Using alternative automatic actions to back up failures of single RAS components.
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re-dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
6. What is required for RAS inadvertent operation?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC-012-0 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the contingency for which
it was designed and not exceed TPL-003-0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.3 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL-001-4 or for System conditions
not defined in TPL-001-4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.3.1 – 4.3.5, which are the
performance requirements common to all planning events P0–P7.
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7. What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific system configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post-Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8. Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS‐SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS; however, the standard drafting team
concluded the classification is unnecessary. The distinction between planning and extreme RAS is
captured in Requirement R4, Part 4.4 and Attachment 1, item III.4 of PRC-012-2 that relates to
single component failure; consequently, there is no need to have a formal classification for this
purpose.
The standard drafting team concluded the SPCS-SAMS distinction between significant and limited
RAS was unnecessary for the purpose of maintaining continuity with PRC-012-1 R1.3 which does
not recognize such a distinction, and problematic due to the difficulty of drawing a universally
satisfactory delineation in generally worded classification criteria.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
9. What constitutes functional modification of a RAS?
Any change in RAS logic, relay settings, control settings, or any other modification that affects
overall RAS functionality, timing, or redundancy level are changes to functionality documented in
the original submission for review. RAS modifications identified by a CAP developed pursuant to
Requirement R6—beyond the substitution of components that preserve the original
functionality—are functional changes.
RAS retirement or removal is a form of RAS functional modification. A RAS-entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in the physical design,
settings, or device custom logic.
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2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor within a RAS component station. Such changes could affect
the throughput timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation settings or custom logic.
10. Why is the RAS-entity identified in the standard and what are its
responsibilities?
The purpose of the RAS-entity is to be the single information conduit with the reviewing RC for all
RAS-owners for each RAS. The RAS-entity needs to coordinate all review materials and any
presentations. If all RAS equipment has a single owner, then the RAS-entity is the RAS-owner, and
that owner speaks for itself.
A RAS can have more than one owner. The RAS-entity is always one of the RAS-owners and is
designated by all RAS-owners. Historically, the owner of the RAS controller (most commonly a
Transmission Owner) is the RAS-entity.
RAS-owners who are not the RAS-entity still have responsibilities as assigned in other NERC
standards, such as equipment maintenance in PRC-005. In addition, when RAS modifications are
needed; e.g., per Requirement R6 or Attachment 1, each RAS-owner must participate in
developing a CAP and accept the specific responsibilities assigned to them in the CAP or
otherwise as described in the revised Attachment 1.
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Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles-Eric Langlois
Hydro-Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards
Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | August 2015
7
Standards Announcement Reminder
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Initial Ballot and Non-binding Poll Open through October 5, 2015
Now Available
An initial ballot for PRC-012-2 – Remedial Action Schemes and a non-binding poll of the associated
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) are open through 8 p.m. Eastern,
Monday, October 5, 2015.
Balloting
Members of the ballot pools associated with this project may log in and submit their votes for the
standard and associated VRFs and VSLs by clicking here.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at [email protected] (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and determine the next steps for the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Formal Comment Period Open through October 5, 2015
Ballot Pools Forming through September 18, 2015
Now Available
A 45-day formal comment period for draft one of PRC-012-2 – Remedial Action Schemes is open through
8 p.m. Eastern, Monday, October 5, 2015.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted
on the project page.
Join the Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, September 18, 2015. Registered Ballot
Body members may join the ballot pools here.
Next Steps
An initial ballot for the standard and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted September 25 – October 5, 2015.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Formal Comment Period Open through October 5, 2015
Ballot Pools Forming through September 18, 2015
Now Available
A 45-day formal comment period for draft one of PRC-012-2 – Remedial Action Schemes is open through
8 p.m. Eastern, Monday, October 5, 2015.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted
on the project page.
Join the Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, September 18, 2015. Registered Ballot
Body members may join the ballot pools here.
Next Steps
An initial ballot for the standard and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted September 25 – October 5, 2015.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Initial Ballot and Non-binding Poll Results
Now Available
A formal comment period and initial ballot for PRC-012-2 – Remedial Action Schemes as well as a nonbinding poll of the associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m.
Eastern, Monday, October 5, 2015.
The standard did not receive sufficient affirmative votes for approval. Voting statistics are listed below,
and the Ballot Results page provides detailed results for the ballot and non-binding poll.
Ballot
Non-binding Poll
Quorum /Approval
Quorum/Supportive Opinions
83.70% / 48.10%
81.54% / 51.79%
Next Steps
The drafting team will consider all comments received during the formal comment and determine the
next steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at (404) 4469675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Survey Report
Survey Details
Name
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes | PRC-012-2
Description
Start Date
8/20/2015
End Date
10/5/2015
Associated Ballots
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 IN 1 ST
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 Non-binding Poll IN
1 NB
Survey Questions
Requirements R1, R2, and R3 pertain to the submittal of Attachment 1 information to the
Reliability Coordinator (RC) for the review of a RAS, the RC using Attachment 2 as a guide for
performing the RAS review, and the RC approving the RAS prior to the RAS being placed in
service. Question 1 is relevant to these activities.
1. RAS review and approval: Do you agree with the RAS review process outlined by
Requirements R1, R2, and R3? If no, please provide the basis for your disagreement and an
alternate proposal.
Yes
No
Requirement R4 mandates that the Transmission Planner perform a technical evaluation
(planning analyses) of each RAS at least once every 60 full calendar months to verify the
continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to
these topics.
2. RAS Periodic Evaluations: Do you agree with the RAS planning evaluation process outlined by
Requirement R4? If no, please provide the basis for your disagreement and an alternate
proposal.
Yes
No
Requirement R4 mandates that the Transmission Planner perform a technical evaluation
(planning analyses) of each RAS at least once every 60 full calendar months to verify the
continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to
these topics.
3. RAS Inadvertent Operation: Do you agree with Requirement 4 Part 4.3 and Attachment 1 which
stipulates that RAS inadvertent operation due to a single component malfunction still satisfies
the System performance requirements common to TPL-001-4 P1-P7 events listed in Parts 4.3.14.3.5? (Note that this requirement remains the same as PRC-012-0 R1.4 except for the allowance
for designed-in security that would prevent RAS inadvertent operation for any single component
malfunction). If no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Requirement R4 mandates that the Transmission Planner perform a technical evaluation
(planning analyses) of each RAS at least once every 60 full calendar months to verify the
continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to
these topics.
4. RAS Single Component Failure: Do you agree with Requirement 4 Part 4.4 and Attachment 1
which stipulates that any RAS intended to satisfy System performance requirements in a TPL
standard must still satisfy those requirements when experiencing a single component
failure? (Note that this requirement remains unchanged from PRC-012-0 R1.3.) If no, please
provide the basis for your disagreement and an alternate proposal.
Yes
No
Requirements R6 and R7 pertain to the development and implementation of Corrective Action
Plans (CAPs). Question 5 addresses these requirements.
5. Corrective Action Plans: Do you agree that the application of Requirements R6 and R7 would
address the reliability objectives associated with CAPs? If no, please provide the basis for your
disagreement and an alternate proposal.
Yes
No
6. Implementation Plan: Do you agree with the Implementation Plan? If no, please provide the
basis for your disagreement and an alternate proposal.
Yes
No
7. If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Responses By Question
Requirements R1, R2, and R3 pertain to the submittal of Attachment 1 information to the
Reliability Coordinator (RC) for the review of a RAS, the RC using Attachment 2 as a guide for
performing the RAS review, and the RC approving the RAS prior to the RAS being placed in
service. Question 1 is relevant to these activities.
1. RAS review and approval: Do you agree with the RAS review process outlined by
Requirements R1, R2, and R3? If no, please provide the basis for your disagreement and an
alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
No
Answer Comment:
The NSRF propose revising R2 to explicitly include the engagement of any
applicable Planning Coordinators with wording like, “Each Reliability Coordinator .
. . shall in conjunction with impacted Transmission Planners and Planning
Coordinators . . .” The inclusion of Transmission Planners and Planning
Coordinators is appropriate because RASs are ‘standing, automatic’ schemes
that are evaluated primarily in the planning horizon and by Transmission
Planners. In general, Reliability Coordinators do not have planning horizon
analysis information or expertise.
We further recommend that M2 and M3 be modified such that acceptable
evidence can be a Reliability Coordinator sponsored peer review by impacted
entities.
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Oncor Electric Delivery believes that it is a good idea to have an independent
party review any RAS. However, 90 days for the review seems more reasonable
since they are just reviewing the scheme.
Additionally Oncor Electric Delivery believes the RAS information required in
attachment 1 contains more than is necessary for a review and cannot always be
obtained for every RAS. In fact, unless the RAS is an existing system during the
review period there are usually no schematics to review so we do not believe it is
appropriate to request schematic diagrams. The second bullet under General
section I asks for “functionality of a new RAS”, which would be a relay functional
diagram that depicts how the scheme works and that would be available during
the review process.
Document Name:
Likes:
0
Dislikes:
0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Requirement R4 mandates that the Transmission Planner perform a technical
evaluation (planning analyses) of each RAS at least once every 60 full calendar
months to verify the continued effectiveness and coordination of the RAS,
including BES performance following an inadvertent operation and single
component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
Document Name:
Likes:
0
Dislikes:
0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
No
a.
R1 references “each RAS-entity shall submit…”, but there should only be
one RAS-entity per RAS, is this correct?
b.
The supplemental material of the Standard states that the RAS owners
needs to select an RAS-entity or else the RC will select the RAS-entity. This
language needs to be in the Standard if it’s going to be enforceable.
c.
For the designation of the RAS-entity between different owners, will
NERC/FERC/Regions require a CFR or JRO agreement? And what happens if
one of the RAS owners is not a NERC registered entity, i.e., not a functional
entity? Please describe what evidence needs to be provided to show designation
of responsibility to the RAS-entity.
d.
Also, most, if not all, new RASs are developed, studied, and reviewed within
the long-term Planning Horizon by PCs and TPs. Modifications/retirements to
existing RASs have the potential to be developed in the Operating Horizon;
therefore, Seminole suggests that R1 be broken up into two requirements, one
addressing modifications/retirements which would be specific to the “Operations
Planning Horizon” and the second addressing “new” RASs specific to the “Longterm Planning Horizon” and applicable to PCs as well.
e.
Can the drafting team define all of the components of an RAS so that
“ownership” can be determined, i.e., what equipment makes up an RAS?
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Yes
Answer Comment:
A. It is unclear why R3 is not structured consistent to R1 even though both
requirements are prerequisites for achieving the same objective of “placing a new
or functionally modified RAS in service or retiring an existing RAS”. Suggest
restructuring R3 as follows for clarity and consistency:
“Prior to placing a new or functionally modified RAS in service or retiring an
existing RAS, the RAS‐ entity shall address each issue identified by the RAS
review (performed pursuant to Requirement R2) and obtain approval of the RAS
from each reviewing Reliability Coordinator.”
B. In R1, the RAS review falls within the purview of one or more RC’s depending
on “the area(s) where the RAS is located.” What attributes define the location of a
RAS? Should the RAS location comprise of only the station(s) where its remedial
action logic processing device(s) is/are installed? Or would the RAS location also
include the stations from where the various RAS inputs are telemetered to the
logic processing device? Would it also include the station(s) at which the RAS
output(s) – that is, remedial actions – are sent? Suggest that the standard
provides clear guidance on what comprises the RAS location. Alternatively,
suggest using a different RAS characteristic in R1 to avoid subjective and
inconsistent interpretations of what comprises RAS location.
Document Name:
Likes:
0
Dislikes:
0
Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
Likes:
0
Dislikes:
0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
No
Answer Comment:
ATC proposes revising R2 to explicitly include the engagement of any applicable
Planning Coordinators with wording like, “Each Reliability Coordinator........ shall
in conjunction with any Planning Coordinators .......”
The inclusion of Planning
Coordinators is appropriate because RASs are ‘standing, automatic’ schemes
that are evaluated primarily in the planning horizon and by Transmission
Planners. In general, Reliability Coordinators do not have planning horizon
analysis information or expertise.
Document Name:
Likes:
0
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for an RAS is determined from TPL studies and
planned system performance. References to the Reliability Coordinator should be
changed to Planning Coordinator. The NERC Functional Model defines the RC
as being “The functional entity that maintains the Real‐ time operating reliability of
the Bulk Electric System within a Reliability Coordinator Area.” It is not
responsible for the planning or installation of a Protection System. The NERC
Functional Model does not support the RC as being the reviewer. The RC
currently does not review nor have the authority to approve any other facility or
protection system installation.
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Answer Comment:
Yes
To remove possible confusion, “on a mutually agreed upon schedule” should be
changed to “on a mutually agreed upon schedule between Reliability
Coordinators and RAS-entities.”
Document Name:
Likes:
0
Dislikes:
0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for a RAS is determined from TPL studies and
planned system performance. The standard correctly provides the RC with an
opportunity to participate in providing opinion. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐ time
operating reliability of the Bulk Electric System within a Reliability Coordinator
Area.” It is not responsible for the planning or installing a Protection System. The
NERC Functional Model does not support the RC as being the reviewer. The RC
currently does not review nor have the authority to approve any other facility or
Protection System installation. Clarification of R3 regarding approval of the RAS
after all issues have been addressed should be made. The approval mentioned
in R3 could be interpreted as an approval that each identified outstanding issue
was addressed and not a complete formal approval of the RAS. If the RC is to
perform the review, we suggest the following rewording for R3:
“Following the review performed pursuant to Requirement R2, the RAS‐ entity
shall address each issue identified by the Reliability Coordinators participating in
the review and obtain final approval(s) for the RAS from each Reliability
Coordinator participating in the review, prior to placing a new or functionally
modified RAS in service or retiring an existing RAS.”
Requirement R4 mandates that the Transmission Planner perform a technical
evaluation (planning analyses) of each RAS at least once every 60 full calendar
months to verify the continued effectiveness and coordination of the RAS,
including BES performance, following an inadvertent operation and single
component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
No
Answer Comment:
The owner of any protection scheme should be responsible for the correct design
and implementation of the scheme – RAS or not. Just like the design of switching
to create a blackstart cranking path by a TOP in EOP-005-2, Requirement 6 must
be verified by that TOP, the owner of the RAS should be held to the same
expectation that the RAS is correctly designed and implemented. If the SDT still
believes that some sort of review is required, then that review should be limited in
scope to reviewing the generic content of the RAS design and not delve into the
technical depth identified in some parts of Attachment 2.
Using the criteria outline by the SDT in its recent webinar, in addition to the
independence of the reviewer and geographic span, the team also mentioned
“expertise in planning, protection, operations, equipment”. The attributes of this
expertise to the level expected do not currently exist in most RC
organizations. RC’s are primarily operating entities (and even then primarily in
real-time) and not experts in planning (beyond the operating time frame),
protection or equipment. Transmission Owners, Transmission Operators and
Transmission Planners normally have that expertise. The FERC acknowledged
the limited RC technical expertise in evaluating details of restoration plans in its
Order 749, Paragraph 38 (“…basis on which a reliability coordinator rejects a
restoration plan will necessarily be based on generic engineering criteria…”). The
review of a RAS by an RC should not be held to a higher expectation due to
similar limited expertise with the equipment and systems involved in a RAS.
The “flexibility” for the RC granted in the requirement to designate a third party
would seem to immediately invalidate the original assumptions that the RC has
the compelling capability to adequately perform the review while meeting the
SDT’s characteristics of the reviewing entity. To allow this, while still requiring the
RC to be responsible for the review, seems like an improper administrative
burden and a potential compliance risk that the RC may assume because it had
to find an entity more qualified than itself to perform the review. If an RC is not
qualified to review all of the items in Attachment 2 then how can it be held
responsible for the results of the review?
Regarding the designation of a third party reviewer, clarification needs to be
made regarding what it means to “retain the responsibility for compliance.” Does
this simply mean that the review takes place or that there is some implied
resulting responsibility for the correct design and implementation that the RC is
now accountable for.
Finally, also regarding the designation of a third party reviewer, is the term “third
party” meant to be any entity not involved in the planning or implementation of the
RAS?
The alterative to using the RC? Although there appears to be a movement to
remove the RRO as a responsible entity from all standards, those organizations
through their membership expertise and committee structures more closely match
the characteristics stated by the SDT – expertise in
planning/protection/operations/equipment, independence by virtue of the diversity
of its members, wide area perspective, and continuity. If for some reason the
SDT, believes that the RRO still should not be involved then an alternative could
be the Planning Coordinator function which should have similar expertise to the
Transmission Planners that are to specify/design a RAS per the functional model
yet would have some independence which the SDT is looking for.
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
On the whole, Reclamation agrees with the RAS review process outlined in
Requirements R1–R3. However, Reclamation believes that RAS-owners should
also be listed in Attachment 1 and Attachment 3 and should be notified of all
RAS-entity communications with the Reliability Coordinator (RC). Reclamation
does not believe that the RAS-entity should be able to release technical
information about a RAS-owner’s equipment without the knowledge of the RASowner.
Document Name:
Likes:
0
Dislikes:
0
David Kiguel - David Kiguel - 8 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
No
Answer Comment:
Florida Power & Light appreciates the efforts of the Standard drafting Team in
consolidating the existing RAS-related Standards into one Standard (PRC-012),
however we disagree with the assertion that the Reliability Coordinator (RC) is
the best choice to review RAS's for new or continued implementation. The RC is
responsible for the operation rather than the planning of the BES. RAS design
and approval is best performed at the planning level. The Planning Coordinator is
responsible for coordinating transmission plans and protection systems and we
believe more appropriate to review, approve and maintain the RAS database.
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Answer Comment:
No
The ISO/RTO Council Standards Review Committee (“SRC”) agrees that the RC
should have to approve the use of RAS. Pursuant to the Functional Model, the
RC does not have the authority to approve relay schemes. Nonetheless, it is
important that the RC be informed of and understand how the RAS impacts the
topology of its area of authority, identify and communicate any reliability issues to
the RAS proponents, and coordinate with the RAS Entity regarding the in-service
date and time of the RAS. We further recommend that M2 and M3 be modified
such that acceptable evidence can be a Reliability Coordinator sponsored peer
review with impacted Transmission Planners and Planning Coordinators.
Therefore, the SRC proposes that Requirement R3 be revised to:
R3. Following the review performed pursuant to Requirement R2, the RAS‐ entity
shall address each identified issue and obtain concurrence from the Reliability
Coordinator that all identified issues are resolved prior to placing a new or
functionally modified RAS in service or retiring an existing RAS.
While the SRC is not opposed to a guideline regarding the performance of RAS
evaluations, Attachment 2 is overly prescriptive and does not allow for impacted
entities to utilize their operational experience and engineering judgment. The
SRC recommends that the introductory paragraph to Attachment 2 be revised to
provide greater flexibility regarding RAS evaluations. The following revisions are
suggested:
The following checklist provides reliability related considerations for the Reliability
Coordinator to consider for inclusion in its evaluation for each new or functionally
modified2 RAS. The RC should utilize the checklist to determine those
considerations that are applicable to the RAS evaluation being performed;
however, RAS evaluations are not limited to the checklist items and the RC may
request additional information on any reliability issue related to the RAS
Requirement R4 mandates that the Transmission Planner perform a technical
evaluation (planning analyses) of each RAS at least once every 60 full calendar
months to verify the continued effectiveness and coordination of the RAS,
including BES performance following an inadvertent operation and single
component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
Document Name:
Likes:
0
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0
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
No
Answer Comment:
With regard to R1, the RAS entity is not typically qualified to provide some of the
information required in Attachment 1, such as Sections II.3, II.4, II.5, and
II.6. This information is typically developed by Planning Coordinator (PC) or
Transmission Planner (TP). RAS owners typically only implement the RAS as
functionally required by the PC or TP. It is noted that the Planning Coordinator is
not listed as an applicable entity and should be.
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for an RAS is determined from TPL studies and
planned system performance. The standard correctly provides the RC with an
opportunity to participate in providing opinion. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐ time
operating reliability of the Bulk Electric System within a Reliability Coordinator
Area.” It is not responsible for the planning or installation of a Protection System.
The NERC Functional Model
does not support the RC as being the reviewer. The RC currently does not
review nor have the authority to approve any other facility or protection system
installation. Clarification of R3 regarding approval of the RAS after all issues
have been addressed should be made. The approval mentioned in R3 could be
interpreted as an approval that each identified outstanding issue was addressed
not complete formal approval of the RAS. If the RC is to perform the review, we
suggest the following:
R3- Following the review performed pursuant to Requirement R2, the RAS‐ entity
shall address each issue identified by the Reliability Coordinators participating in
the review and obtain final approval(s) for the RAS from each Reliability
Coordinator participating in the review, prior to placing a new or functionally
modified RAS in service or retiring an existing RAS.
With regard to R3, some of the identified issues would be most appropriately
addressed by the PC or TP, especially the items in Section II of Attachment 1. It
is inappropriate for RAS entity to assume compliance responsibility for addressing
each identified issue. The RAS owner for the RAS issues should be the
responsible entity.
Requirement R4 mandates that the Transmission Planner perform a technical
evaluation (planning analyses) of each RAS at least once every 60 full calendar
months to verify the continued effectiveness and coordination of the RAS,
including BES performance following an inadvertent operation and single
component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
Document Name:
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0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
No
Answer Comment:
As Dominion stated in its previous comments, we believe that RAS should be
reviewed and approved in both the planning and operating horizons by
designated entities within whose area(s) the Facility (ies) the RAS is designed to
protect reside.
Dominion suggests the following specific changes to R1: Prior to placing a new or
functionally modified RAS in service or retiring an existing RAS, each RAS‐ entity
shall submit the information identified in Attachment 1 for review to the Reliability
Coordinator(s) and Transmission Planner(s) within whose respective area(s)
the Element(s) or Facility(ies) for which the RAS is designed to protect is
(are) located..
Document Name:
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0
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0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
No
Answer Comment:
See the comment in #7.1. In addition, the Transmission Planner should be a
required participant in developing Attachment 1 and at least be responsible for
Section II in Attachment 1. Finally, the obligation in R3 that a RAS-entity address
issues identified pursuant to R2 is incomplete. R3 should also place compliance
obligations on the Transmission Planner and the RAS-owners to participate in
addressing any issues under R3.
Document Name:
Likes:
4
Dislikes:
0
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
No
Answer Comment:
Regarding Requirement R1, the RAS-entity is not typically qualified to provide
some of the information required in Attachment 1, such as Sections II.3, II.4, II.5,
and II.6. This information is typically developed by the Planning Coordinator (PC)
or Transmission Planner (TP). RAS-owners typically only implement the RAS as
functionally required by the PC or TP. The Planning Coordinator should be listed
as an applicable entity.
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for a RAS is determined from TPL studies and
planned system performance. The standard correctly provides the RC with an
opportunity to participate in providing opinion. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐ time
operating reliability of the Bulk Electric System within a Reliability Coordinator
Area.” It is not responsible for the planning or installation of a Protection System.
The NERC Functional Model does not support the RC as being the reviewer. The
RC currently does not review nor have the authority to approve any other facility
or protection system installation. Clarification of R3 regarding approval of the
RAS after all issues have been addressed should be made. The approval
mentioned in R3 could be interpreted as an approval that each identified
outstanding issue was addressed not complete formal approval of the RAS. If the
RC is to perform the review, we suggest the following:
R3- Following the review performed pursuant to Requirement R2, the RAS‐ entity
shall address each issue identified by the Reliability Coordinators participating in
the review and obtain final approval(s) for the RAS from each Reliability
Coordinator participating in the review, prior to placing a new or functionally
modified RAS in service or retiring an existing RAS.
Regarding Requirement R3 some of the identified issues would be most
appropriately addressed by the PC or TP, especially the items in Section II of
Attachment 1 as mentioned earlier. It is inappropriate for the RAS-entity to
assume compliance responsibility for addressing each identified issue. The
RAS-owner for the RAS issues should be the responsible entity.
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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Document Name:
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0
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0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
No
Answer Comment:
PJM supports the comments submitted by the ISO/RTO Council.
Document Name:
Likes:
0
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0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
No
Answer Comment:
R1, R2 and R3 do not differentiate between the functional aspects and design
aspects of RAS. The functional requirements for a RAS, i.e. system conditions
and triggering contingencies for which RAS is required as well as RAS actions to
meet system performance requirement (as per TPL-001-4), are studied and
identified by Transmission Planner and/or Planning Coordinator and not by the
RAS owner/entity. The RAS owner/entity designs the RAS after TP or PC
determines the functional requirements. The information listed in part II of
attachment 1 is about functional requirements and can be provided by TP or
PC. Most of the information listed in part I is repeat of part II. The rest, e.g.,
maps, one-line diagrams, in-service date, etc., can also be provided by TP or PC
who determined the functional requirements. The information in part III, which is
related to the RAS design, is provided by the RAS owner/entity. RAS owners
typically only implement the RAS as functionally required by the PC or TP. It is
noted that the Planning Coordinator is not listed as an applicable entity and
should be. With regard to R3, some of the identified issues would be most
appropriately addressed by the PC or TP, especially the items in Section II of
Attachment 1.
We suggest that R1, R2 and R3 and the related attachments be split in two parts:
a) functional aspects, where TP or PC will be required to determine the functional
requirements of the RAS and provide relevant information to RC for review, and
b) design aspects, where RAS owner/entity will be required to design the RAS to
meet those functional requirements and provide relevant information to RC for
review.
Document Name:
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0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
No
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Document Name:
Likes:
0
Dislikes:
0
Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Gallo - Austin Energy - 6 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Yes
Answer Comment:
We agree with the checklist for the Reliability Coordinator to receive the proper
information pertaining to the RAS and conducting a proper analysis. Additionally,
we commend the drafting team for addressing the timing requirements in the
Requirement R3 Rationale Box. We feel this will give the industry amply of
enough time to address any issues identified by the Reliability Coordinator
through their analysis.
Document Name:
Likes:
0
Dislikes:
0
Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
No
Answer Comment:
Florida Power and Light appreciates the efforts of the Standard Drafting Team in
consolidating the exsiting RAS-related Standards into one Standard - PRC-012-2,
however we disagree with the assertion that the Reliability Coordinator (RC) is
the best choice to review the RAS's for new and continued implementation. The
RC is responsible for the operation rather than the planning of the BES. RAS
design and approval is best done at the Planning level. The Planning
Coordinator is responsible for coordinating transmission plans and protection
systems and we believe more appropriate to review, approve, and maintain the
RAS database.
Document Name:
Likes:
0
Dislikes:
0
Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
Yes
In Requirement R3, the term “shall address” does not necessarily indicate the
issue must be resolved as the Supplemental Material indicates. Texas RE
recommends strengthening the requirement language to “shall resolve” or “shall
implement”.
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
1. RAS review should be conducted by the Planning Coordinator and not the
Reliability Coordinator. Oversight of the wide-area in the planning horizon is the
job of the Planning Coordinator. This will be a significant amount of extra work for
the RCs who should be focused on near-term operational reliability.
2. R1 should state a time frame the data should be submitted to the RC, such as
four month prior to implementation of the RAS. Otherwise, the burden will be
placed on the RC to conduct the study on the RAS-entities schedule.
3. There is no requirement to notify impacted neighboring entities. When a RAS
is implemented it can have a significant impact on neighboring
entities. Neighboring entities need to have an opportunity to study the impact of
the RAS.
Document Name:
Likes:
0
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0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
R1, R2 and R3 do not differentiate between the functional aspects and design
aspects of RAS. The functional requirements for a RAS, i.e. system conditions
and triggering contingencies for which RAS is required as well as RAS actions to
meet system performance requirements (as per TPL-001-4), are studied and
identified by the TP and/or PC and not by the RAS owner/entity. The RAS
owner/entity designs the RAS after the TP or PC determines its functional
requirements. Therefore, the information listed in part II of attachment 1 is about
functional requirements and can only be provided by a TP or PC in most
instances.
Most of the information listed in Part I is repeated in Part II. The remaining
information listed, e.g., maps, one-line diagrams, in-service date, etc., can also be
provided by the TP or PC, who determines the functional requirements. The
information in Part III, which is related to the RAS design, is provided by the RAS
owner/entity.
Hydro One Networks Inc. suggests that R1, R2 and R3 and the related
attachments be split in two parts: a) functional aspects, where the TP or PC will
be required to determine the functional requirements of the RAS and provide
relevant information to the RC for review, and b) design aspects, where the RAS
owner/entity will be required to design the RAS to meet those functional
requirements and provide relevant information to the RC for review.
In addition, it is inappropriate for the RAS entity to assume compliance
responsibility for addressing each identified issue. The RAS owner for the RAS
issues should be the responsible entity; this would be more in agreement with the
assignment of accountabilities in R6.
Please also note our following comments with respect to relaxing the design
review for a class of RAS.
Document Name:
Likes:
1
Dislikes:
0
Hydro One Networks, Inc., 3, Malozewski Paul
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
No
Answer Comment:
R2 has an option of a four month schedule or a mutually agreed upon
schedule. It is understood that setting a goal for a review within the operations
time-frame is important, but it seems like the standard is trying to achieve two
separate goals at once.
The first goal is to review the proposed change to determine whether it involves a
CAP and identifies any current risks to reliability of the system which, as identified
in the standard, might require use of System operating limits until the CAP is
complete. This review needs to be completed quickly to minimize risk to the BES,
but requires much less effort than a full review of the performance of the new
RAS. In this instance four full-calendar months would seem to be too long of a
time period.
The second goal is to complete the full review from a planning perspective. Each
region already has a review and approval process in place. It seems arbitrary
and unnecessary to impose the 4 month requirement rather than allowing the RC
to follow a schedule or process it has already established. In this instance the four
months would seem too short a time period in many cases due to the way these
reviews are conducted (and by whom they are conducted) – so long as the risk to
the BES reliability is already understood up-front, there is no reason to rush this
portion of the work. In many cases, the RC in question may not possess the
necessary staff / skills to perform what is required in Attachment 2, and may need
to retain the services of others (consultants or perhaps area PCs or TPs), which
will take time.
FMPA believes both issues could be resolved if R2 separated the near-term need
to quickly assess BES reliability risk in the Operating Horizon from the long-term
need to assess the details of the performance of the proposed scheme –
particularly in cases where the proposed change is due to an identified issue with
a subsequent CAP. Doing this first step on fast track would then allow each RC
to define the schedule for the remaining review as per their regional practices.
Also, it would be beneficial to include all RAS-owners and their contact
information in the RAS database.
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
No
Answer Comment:
(1) We question why the RC was selected as the reviewing entity in this
context. RC System Operators are not required to be “familiar with” (Reliability
Standard PRC-001) or “have knowledge of” (proposed Reliability Standard TOP009) the purpose and limitations of a RAS. Moreover, after the RC has
conducted its initial review (Requirement R2) and the RAS-entity has addressed
the identified issues, there is no timeframe required for the RC to conduct a final
review for approval. We suggest rewording Requirement R3 to require both the
RAS-entity and the RC to address each identified issue within a mutually agreed
upon timeframe and concluded by a final RC review. Documentation regarding
an approval of the RC following its final review should then be listed as
acceptable evidence in Measure M3.
(2) We would also like the drafting team to state that an existing SPS will not
need to go through the RC approval process even though the new definition of
RAS could be applied as a new RAS device. The standard is unclear regarding
which equipment will need to go through the RC approval process, existing
SPS/RAS or new/changed RAS equipment? One possible solution is to state that
all SPS and RAS equipment that are in service on the effective date of the
proposed standard are considered RAS going forward and will not be required to
go through the RC approval process.
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
No
BPA believes R2’s timeline of four-full-calendar months for RC review of RAS
submission is too generous; it is inconsistent with regional practice. BPA
proposes two weeks as appropriate, with less potential negative impact. The
schedule should be short enough to accommodate the needs of the RAS owners
and the “mutually agreed upon schedule” should apply if more time is needed.
Document Name:
Likes:
0
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0
Requirement R4 mandates that the Transmission Planner perform a technical evaluation
(planning analyses) of each RAS at least once every 60 full calendar months to verify the
continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to
these topics.
2. RAS Periodic Evaluations: Do you agree with the RAS planning evaluation process outlined by
Requirement R4? If no, please provide the basis for your disagreement and an alternate
proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
No
Answer Comment:
For R4, we propose revised wording to explicitly include any applicable Planning
Coordinators with wording like, “. . . provide the results including any identified
deficiencies to the RAS-owner(s), the reviewing Reliability Coordinators(s) and
impacted Transmission Planners and Planning Coordinators.”
Again, the inclusion of impacted Transmission Planners and Planning
Coordinators is appropriate because these entities will generally have the best
planning horizon information and expertise to review the evaluation.
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
We agree the Transmission Planner should periodically evaluate each RAS but
there needs to be a mechanism by which the RAS-owners are required to share
the RAS information with the Transmission Planner.
Document Name:
Likes:
0
Dislikes:
0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
No
Answer Comment:
The process is not clear about the responsibility for a RAS which is activated in
multiple Transmission Planner areas such as WECC-1. The standard should
clearly specify whose responsibility it is to perform technical studies. APS
suggests the following language:
“For a RAS which is activated in multiple Transmission Planning areas, a mutually
agreed upon Transmission Planner of one of the multiple Transmission Planning
areas shall perform an evaluation of the RAS at least once every 60‐ full‐
calendar‐ months and provide the RAS‐ owner(s) and the reviewing Reliability
Coordinator(s) the results including any identified deficiencies.”
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
No
Answer Comment:
a.
For R4, can the TP merely provide the data to the RAS owners and the
RAS-entity report the information to the RC?
b.
In R4.2, please give additional detail as to what “adverse interactions”
cover?
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
No
Answer Comment:
The rationale and/or technical guidance does not make a convincing case for why
the periodic evaluation of RAS must be a planning horizon analysis, and thus
suited to be performed by Transmission Planner. As currently drafted, R4 seems
to have an underlying premise that the periodic evaluation needs to be performed
for the near-term planning horizon, which makes the periodic evaluation akin to
the typical (future year) planning studies performed by Transmission
Planner. However, the rationale for R4 does not provide any justification for the
above. In fact, performing a planning horizon analysis is inconsistent with, if not
contradictory to, the following reliability need stated in the rationale “A periodic
evaluation is needed because (material) changes in system topology or operating
conditions that have occurred since the previous RAS evaluation – or initial
review – was completed…” Doesn’t this imply that the periodic RAS evaluation is
for past changes, not the future planned changes? If so, wouldn’t the periodic
RAS evaluation be more akin to Operational Planning Analysis (OPA) in the
operating horizon? Is there a reason why an OPA would not be able to
comprehensively address items 4.1 – 4.4 required for periodic RAS
evaluation? We note that the existing R4 rationale makes an inadequate claim
that “items required to be addressed in the evaluation are planning analyses”,
which is a weak basis for concluding that “consequently, the Transmission
Planner is the functional entity best suited to perform the analyses.” Based on all
the above reasons, we contend that the reliability objectives of periodic RAS
evaluation are more effectively achieved based on an operating horizon analysis
like OPA. Therefore, the periodic RAS evaluation lends itself better to be
performed by the Transmission Operator (or perhaps even the Reliability
Coordinator).
Document Name:
Likes:
0
Dislikes:
0
Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
Likes:
0
Dislikes:
0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Yes
Answer Comment:
Suggest clarifying in R4 that the evaluation is a technical evaluation as stated
below:
Each Transmission Planner shall perform a technical evaluation (planning
analyses) of each RAS within its planning area at least once every 60‐ full‐
calendar‐ months and provide the RAS‐ owner(s) and the reviewing Reliability
Coordinator(s) the results including any identified deficiencies.
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
No
Answer Comment:
For R4, ATC proposes revising the wording to explicitly include any applicable
Planning Coordinators with wording like, “. . . provide the results including any
identified deficiencies to the RAS-owner(s), the reviewing Reliability
Coordinators(s) and any applicable Planning Coordinators.”
Again, the inclusion of Planning Coordinators is appropriate because the
Transmission Planner evaluation will be for the planning horizon and Planning
Coordinators will generally have the best information and expertise to review the
evaluation.
Document Name:
Likes:
0
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
The RAS-entity would be more appropriate to be specified in R4 instead of the
RAS-owner
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The RAS-entity would be more appropriate to be specified in R4 instead of the
RAS-owner.
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Kiguel - David Kiguel - 8 Selected Answer:
No
Answer Comment:
While generally supportive of this standard, I have concerns over assigning
longer term assessment to Transmission Planner rather than to the Planning
Coordinator.
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
No
Answer Comment:
1.
i.
It is unclear why the Transmission Planner would provide results
of the evaluation to each of the RAS‐ owner(s) and not the RASentity. A RAS typically operates as a single scheme and thus the
RAS-entity can coordinate with all the RAS-owners regarding
such evaluation results.
ii.
ReliabilityFirst currently reviews each SPS at least once every
five years for compliance with our Regional Criteria in
accordance with fill-in-the-blank NERC standard PRC-012,
Requirement R1. ReliabilityFirst has concerns with the 60 month
review cycle in Requirement R4 as there may be instances in
which a SPS which was reviewed by RF in the 2000 timeframe
could theoretically not be reviewed until the 2020
timeframe. ReliabilityFirst believes a potential gap of 10 years in
between reviews may have reliability impact. In order to prevent
such a potential gap, ReliabilityFirst recommends the following
recommendation for consideration:
a. Each Transmission Planner shall perform an evaluation
of each RAS within its planning area at least once every
60‐ full‐ calendar‐ months [since its last evaluation]
and provide the RAS‐ owner(s) and the reviewing
Reliability Coordinator(s) the results including any
identified deficiencies. Each evaluation shall determine
whether:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
No
Answer Comment:
Many Transmission Owner organizations also perform the transmission planning
function and as such, are also registered as the Transmission Planners (for the
assets that they own). The SRC believes that a proper, unbiased evaluation of
RAS performance should be conducted by an entity that is not in the same
organization as the TO and has a broader perspective, which is important
because RAS’s intended function and operational impact may affect more than
one TO and TP. The SRC respectfully asserts that, given the importance of
independence and a wide-area perspective, the Planning Coordinator is a more
appropriate entity to perform Requirement R4 . The SRC therefore suggests
replacing the TP with the PC or, at a minimum, requiring a review of results and
provision of feedback by the Planning Coordinator to the Transmission Planner.
This proposal is consistent with the basis for assigning R2 to the RC rather than
the TOP.
Document Name:
Likes:
0
Dislikes:
0
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
No
Answer Comment:
The RAS-entity would be more appropriate to be specified in R4 instead of the
RAS-owner.
The RAS-entity and the RAS-owner should be provided with the result of the
review. The PC may be more appropriately qualified to review certain RAS than
the TP.
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Dominion suggests clarifying in R4 that the evaluation is a technical evaluation as
stated below:
Each Transmission Planner shall perform a technical evaluation (planning
analyses) evaluation of each RAS within its planning area at least once every
60‐ full‐ calendar‐ months and provide the RAS‐ owner(s) and the reviewing
Reliability Coordinator(s) the results including any identified deficiencies.
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
No
Answer Comment:
R4 should be modified to include a new part 4.5 that would require the
Transmission Planner to identify any performance deficiencies in the RAS as well
as alternatives for mitigating or correcting such deficiencies. The RAS-owners
would not have the capability to identify alternatives for correcting deficiencies.
Document Name:
Likes:
4
Dislikes:
0
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
No
Answer Comment:
It would be more appropriate to specify the RAS-entity in R4 instead of the RASowner.
The RAS-entity and the RAS-owner should be provided with the results of the
review. The PC may be more appropriately qualified to review certain RAS than
the TP. Consider revising R4 to read “Each Transmission Planner shall
evaluate…”.
Add wording to the Rationale for Requirement R4 to clarify that the intent is not to
evaluate all RAS at the same time, but that each RAS is to be evaluated on a 60
full calendar month cycle.
Would the Planning Coordinator ever perform this evaluation instead of the
Transmission Planner?
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
No
Answer Comment:
PJM supports the comments submitted by the ISO/RTO Council.
Document Name:
Likes:
0
Dislikes:
0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
No
Answer Comment:
How would a scenario be addressed in which a RAS spans two or more
Transmission Planner areas?
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
No
Answer Comment:
TANC has concerns with the current language in R4 because appears to assume
that a RAS exists within a single planning area. NERC has not defined the term
“planning area”, which creates ambiguity in the requirement’s language that
states “Each Transmission Planner shall perform an evaluation of each RAS
within its planning area.” This ambiguity is further compounded in circumstances
where a single RAS exists within the footprints of multiple Transmission Planners
(and Planning Coordinators). In such cases, it is unclear which Transmission
Planners associated with the multiple RAS-owners for a single RAS would have
responsibility in accordance with this standard.
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
No
Answer Comment:
We generally agree with the process outlined by R4, but reiterate our comment
that the Planning Coordinator, NOT the TP, should the entity responsible for this
requirement.
Many Transmission Owner organizations also perform the transmission planning
function and as such, are also registered as the Transmission Planners (for the
assets that they own). A proper and unbiased evaluation of the RAS performance
should be conducted by an entity that is not in the same organization as the TO
and has a wider perspective than the TO and TP. And since the RAS intended
function its operational impact may affect more than one TOs and TPs, a PC is
the most appropriate entity to perform this task than the TP, both from an
independence and a wide area perspectives. We therefore suggest replacing the
TP with the PC. This proposal is consistent with the basis for assigning R2 to the
RC rather than the TOP.
The RAS-entity and the RAS-owner should be provided with the result of the
review. The PC may be more appropriately qualified to review certain RAS than
the TP.
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
No
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Document Name:
Likes:
0
Dislikes:
0
Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Gallo - Austin Energy - 6 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Answer Comment:
No
To address existing entity NERC registration in the ERCOT region, “Transmission
Planner” should be replaced with “Transmission Planner (in the ERCOT Region
this applies to the Planning Authority and /or Reliability Coordinator.)”
R4. Each Transmission Planner (in the ERCOT Region this applies to the
Planning Authority and /or Reliability Coordinator) shall perform an evaluation of
each RAS within its planning area at least once every 60‐ full‐ calendar‐ months
and provide the RAS‐ owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each evaluation shall determine
whether: [Violation Risk Factor: Medium] [Time Horizon: Long‐ term Planning]
Document Name:
Likes:
0
Dislikes:
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Yes
Answer Comment:
We feel that the Transmission Planner also conducting an analysis will help
address changes to the RAS which could impact the BES. Additionally, we like
the fact that the analysis can be performed earlier if changes to the systems
topology or system operating conditions has a potential impact on the BES (as
mentioned in the second paragraph of the Rationale Box for Requirement R4).
Document Name:
Likes:
0
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0
Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
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0
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0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
No
Answer Comment:
Texas RE asks the drafting team to consider adding the Planning Coordinator to
Requirement R4 for instances where a RAS covers multiple Transmission
Planner areas. The current practice the ERCOT region is ERCOT conducts the
5-year review of each RAS; however, ERCOT is the Planning Coordinator, not a
Transmission Planner.
Texas RE asks the drafting about the term “60-full-calendar-months” in
Requirements R4 and R6. The term is not defined and is not consistent with
other standards and requirements. PRC-006 indicates five years, PRC-010-1
indicates 60 calendar months, and PRC-014 indicates five years. Texas RE
recommends not introducing new terms and to be as consistent as possible. Is
the SDT defining a “full calendar month” or “calendar year”? The RSAW is not
the place to define a new term and the definition is different than terms used in
PRC-005. This definition is misleading to those reviewing the document and
could potentially exacerbate reliability issues nearly seven years based on the
“definition” provided in the Note to Auditor section of R4 in the RSAW.
The intent of Requirement R9 should be to update once per year not once per
729 days (2 years minus 1 day) which would be allowable by the definition of full
calendar year as stated in the RSAW.
Texas RE recommends defining the term “planning area”. It should be
prescriptive enough to include GOs and DPs that are RAS-owners, i.e. generator
owners or distribution providers that own all or part of a RAS. In Requirement R4,
by default a Generator Owner or Distribution Provider owned RAS would be
within a Transmission Planners planning area, correct? Please confirm or give
specifics as to why a GO or DP owned RAS would not be within a Transmission
Planners planning area.
Document Name:
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0
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0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The RAS owner must review the RASs in R4, R5, R6. Nowhere does it give the
reviewing Reliability Coordinator the authority to dispute the evaluation in R4,
dispute the analysis in R5, and require changes to the corrective action plan in
R6. RC is just provided the results of analysis but is not given any authority to do
anything with them.
Document Name:
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0
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0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
Although Hydro One Networks Inc. agrees with the evaluation process, we
emphasize (as described above in Q1) that the evaluation of each new RAS must
also be required from the TP or PC before the RAS is approved and implemented
by the RAS owner/entity. We recognize that it is inconsistent to require the initial
assessment of a RAS from a RAS owner/entity (in R1), and the
subsequent/periodic assessments from a TP (in R4).
Document Name:
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0
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0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Yes
Answer Comment:
Recommend changing 60 full calendar months to 5 calendar years, to allow the
RAS evaluation to fit within the annual Planning Assessment process which may
vary from year to year.
Document Name:
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0
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0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
No
Answer Comment:
(1) We believe 60 calendar months is an appropriate amount of time to conduct
RAS periodic evaluations. However, we do not believe the TP has sufficient
visibility outside of its area to determine if the BES will remain stable or the
occurrence of a Cascading outage will be minimized following the inadvertent
operation of a RAS from any single RAS component malfunction. These “widearea” views are only available to the PC. We believe the requirement should be
rewritten to include the PC as an applicable entity for these technical evaluations.
(2) We have concerns that the requirement does not identify what events will
trigger when the clock begins on the 60 calendar month timeframe. We ask the
SDT to clarify when the clock starts for these periodic evaluations – is it after the
initial installation, after the latest modification to RAS functionality, or following a
response to a CAP?
Document Name:
Likes:
0
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0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Requirement R4 mandates that the Transmission Planner perform a technical evaluation
(planning analyses) of each RAS at least once every 60 full calendar months to verify the
continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to
these topics.
3. RAS Inadvertent Operation: Do you agree with Requirement 4 Part 4.3 and Attachment 1 which
stipulates that RAS inadvertent operation due to a single component malfunction still satisfies
the System performance requirements common to TPL-001-4 P1-P7 events listed in Parts 4.3.14.3.5? (Note that this requirement remains the same as PRC-012-0 R1.4 except for the allowance
for designed-in security that would prevent RAS inadvertent operation for any single component
malfunction). If no, please provide the basis for your disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
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0
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0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
No
Answer Comment:
Clarity is needed in R4 as to exactly what the trigger is for the 60-full-calendarmonths periodic review. Is it tied, perhaps, to the in-service status? In addition,
rather than a 60 full month periodic review, AEP suggests a “5 calendar year”
review. This would allow flexibility for an entity to integrate this work into its
annual planning cycle.
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
No
Answer Comment:
Needs further clarification. The Transmission Planner or the group that owns the
RAS should be responsible for the evaluation, coordination and testing of the
RAS.
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0
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0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
No
Answer Comment:
Recommend deleting Part 4.3 since we find it hard to conceive how the
inadvertent operation of RAS can result in unacceptable system performance
when the primary motivation for installing any RAS is to achieve acceptable
system performance. We acknowledge that inadvertent RAS operation is
undesirable, but we also recognize that it is fundamentally the same as a RAS
misoperation. And therefore, any adverse reliability impact due to inadvertent
RAS operation would get addressed in R5 during RAS operational performance
analysis. Consequently, we do not see any reliability risk, and thus no associated
compelling need, to identify the potentially unacceptable system performance
based on simulations/analyses performed for periodic RAS evaluation using
models that reflect “typical” rather than actual operating conditions. Although we
agree with the goal of a robust RAS design that is not susceptible to RAS
misoperation caused by the malfunction of a single component, we also believe
this objective is effectively accomplished by any corrective action plan spawned
by the RAS operational performance analysis in R5.
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Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
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0
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0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important however and we suggest that only 4.3.1 and 4.3.2 as well
as controlling system separation are the only aspects that are needed. In
Attachment 2 we agree that inadvertent operation needs to be understood
however if that inadvertent operation does not cause one of the three significant
adverse impacts to the reliability of the BES then the RAS should not be subject
to additional requirements which likely will only have a localized effect. The
addition of this language in R 4.3.3, 4.3.4, and 4.3.5 unnecessarily may result in
local RAS to have increased design complexity, additional components which
may increase the likelihood of misoperation (decreasing the reliability of the RAS)
and excessive costs. We suggest the SDT consider that all RAS which have a
wider impact, whose inadvertent operation could result in Cascading, System
Separation or instability be subject to this standard and its design
requirements. To place these requirements as written on all RAS would be of
little or no benefit to achieving an adequate level of reliability on the BES and
based on this we would characterize this as placing a requirement such as those
removed by Paragraph 81 in the standard. Furthermore, this could actually be a
detriment to the reliable operation of a local RAS subjecting it to unnecessary
additional design requirements.
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Answer Comment:
Yes
Consider adding 4.3.6 “Frequency Trigger Limits (FTLs) shall be within
acceptable limits as established”
Document Name:
Likes:
0
Dislikes:
0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important; however, we suggest that 4.3.1, 4.3.2, and controlling
system separation should be the only aspects that are needed. We do not
understand the intent of 4.3.3 “applicable facility ratings.” Is this normal,
emergency, DAL (drastic action limit), etc.? In Attachment 2, we agree that
inadvertent operation needs to be understood however if that inadvertent
operation does not cause one of the three significant adverse impacts to the
reliability of the BES, then the RAS should not be subject to additional
requirements when the inadvertent operation likely will only have a localized
effect. The addition of this unnecessary language in R 4.3.3, 4.3.4, and 4.3.5
may result in local RAS having increased design complexity, additional
components that may increase the likelihood of misoperation (decreasing the
reliability of the RAS) and excessive costs. We suggest the SDT consider that all
RAS that have a wider impact, whose inadvertent operation could result in
Cascading, System Separation, or instability, be subject to this standard and its
design requirements. To place these requirements as written on all RAS would
be of little or no benefit to achieving an adequate level of reliability on the BES
and based on this we would characterize this as a Paragraph 81 requirement in
the standard. Furthermore, this could actually be a detriment to the reliable
operation of a local RAS, subjecting it to unnecessary additional design
requirements.
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Kiguel - David Kiguel - 8 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important however we suggest that only 4.3.1 and 4.3.2 as well as
controlling system separation are the only aspects that are needed. We do not
understand the intent of 4.3.3 “applicable facility ratings”. Is this normal,
emergency, DAL (drastic action limit), etc.? In Attachment 2 we agree that
inadvertent operation needs to be understood however if that inadvertent
operation does not cause one of the three significant adverse impacts to the
reliability of the BES then the RAS should not be subject to additional
requirements which likely will only have a localized effect. The addition of this
language in R 4.3.3, 4.3.4, and 4.3.5 unnecessarily may result in local RAS to
have increased design complexity, additional components which may increase
the likelihood of misoperation (decreasing the reliability of the RAS) and
excessive costs. We suggest the SDT consider that all RAS which have a wider
impact, whose inadvertent operation could result in Cascading, System
Separation or instability be subject to this standard and its design
requirements. To place these requirements as written on all RAS would be of
little or no benefit to achieving an adequate level of reliability on the BES and
based on this we would characterize this as placing a Paragraph 81 requirement
in the standard. Furthermore, this could actually be a detriment to the reliable
operation of a local RAS subjecting it to unnecessary additional design
requirements.
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
No
Answer Comment:
Dominion concurs with the idea of an inadvertent operations test; however R4.3.5
transient voltage response should not be part of that test. Preventing FIDVR is
only necessary to prevent cascading due to motor stalling (an unlikely outcome)
which is addressed under R4.3.2. Dominion believes that slow transient voltage
response that does not lead to cascading and is a customer power quality issue
and not a reliability issue.
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Answer Comment:
No comment.
Document Name:
Likes:
4
Dislikes:
0
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important. However, we suggest that only sub-Parts 4.3.1 and 4.3.2
as well as controlling system separation are the only aspects that are
needed. We do not understand the intent of sub-Part 4.3.3 “applicable facility
ratings”. Is this normal, emergency, DAL (drastic action limit), etc.? In
Attachment 2 we agree that inadvertent operation needs to be
understood. However, if that inadvertent operation does not cause one of the
three significant adverse impacts to the reliability of the BES then the RAS should
not be subject to additional requirements which likely will only have a localized
effect. The addition of this language in sub-Parts 4.3.3, 4.3.4, and 4.3.5
unnecessarily may result in local RAS to have increased design complexity,
additional components which may increase the likelihood of misoperation
(decreasing the reliability of the RAS) and excessive costs. We suggest the SDT
consider that all RAS that have a wider impact, those whose inadvertent
operation could result in Cascading, System Separation or instability be subject to
this standard and its design requirements. To place these requirements as
written on all RAS would be of little or no benefit to achieving an adequate level of
reliability on the BES, and based on this we would characterize this as placing a
Paragraph 81 requirement in the standard. Furthermore, this could actually be a
detriment to the reliable operation of a local RAS subjecting it to unnecessary
additional design requirements.
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Yes
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
No
Answer Comment:
At the present time there are RAS in service that have a limited local impact. To
universally apply the same design criteria to all RAS regardless of their impact on
BES in case of an inadvertent operation may have no cost benefit in the case of
the RAS installed to address local problems.
We propose the following to be included in the standard:
An inadvertent operation in the RAS, when the RAS is intended to operate, does
not result in any of the following conditions on the BES:
1.
Cascading
2.
Uncontrolled System Separation
3.
Instability
When the criteria mentioned above is not met a secure design will be required.
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Yes
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Document Name:
Likes:
0
Dislikes:
0
Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Gallo - Austin Energy - 6 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
Yes
The SDT may want to consider adding “Applicable System Operating Limits shall
not be exceeded” as a sub-bullet to Requirement R4.3.
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
No
FMPA agrees with the intent of R4.3 – that construction of devices/systems as an
integral part of the BES should be held to same standards as construction of
physical facilities. However, we believe there is a problem with the wording of the
first sentence. It is possible to read the first sentence to be requiring that
inadvertent operation of the RAS due to a single component malfunction be
studied as a planning event regardless of whether the system is designed to
prevent such an event from occurring. FMPA believes the intent of the language
is that items 4.3.1 through 4.3.5 only apply if single component malfunction does
actually produce an operation of the RAS. If this were not true (e.g. if the
language in R4.3 was requiring the study of the inadvertent RAS operation
against the criteria in 4.3.1 through 4.3.5 regardless of whether a single
component malfunction could actually cause the RAS to operate), the language
would essentially be requiring that TPL-001-4 Planning Event criteria be applied
to what amounts to an Extreme Event. This is partly because of the use of the
term “malfunction” as opposed to “failure”. This is not consistent with TPL-001-4
which refers to protection system “failures”. This is an important distinction
because typically protection systems are designed such that if a component fails,
it does so without issuing a false trip. A malfunction can be interpreted to mean a
large number of absurdly unlikely things which are over and above the level of
rigor required by TPL-001-4. FMPA understands that the SDT desired to
consider the use of non-“protection system” control devices using this standard,
but the language as written does not allow those entities that are using protective
devices to take credit for basic design principles such as redundancy. Suggest
either expressly allowing entities to take credit for redundancy, switching to using
the term “failure” or both.
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
No
Answer Comment:
Certain aspects of the TPL-001-4 P1-P7 events identify actions under a steady
state or a stability assessment. We have concerns that applicable Facility Rating
exceedances and BES voltages deviations, as identified with TPL-001-4, are only
applicable under steady state conditions. We recommend the SDT modify
Requirement R4 to identify these references within the context of a steady state
assessment, instead of a transient state, to align with existing NERC standards.
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Requirement R4 mandates that the Transmission Planner perform a technical evaluation
(planning analyses) of each RAS at least once every 60 full calendar months to verify the
continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to
these topics.
4. RAS Single Component Failure: Do you agree with Requirement 4 Part 4.4 and Attachment 1
which stipulates that any RAS intended to satisfy System performance requirements in a TPL
standard must still satisfy those requirements when experiencing a single component
failure? (Note that this requirement remains unchanged from PRC-012-0 R1.3.) If no, please
provide the basis for your disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
No
Answer Comment:
The NSRF recommends two modifications to Part 4.4.:
One modification is to explicitly include “option c” in the Implementation section of
the Supplemental Material associated with the Standard. The revised wording
could be, “A single component failure in RAS, when the RAS is intended to
operate, or alternative automatic actions back up the failures of single RAS
components . . .” Including text about the alternative option in the standard, rather
than the Supplemental Material would assure that it cannot be dismissed by an
auditor.
The other modification is to remove the unnecessary linking of R4.4 to TPL-001-4
performance requirements with linking to the performance requirements already
expressed in R4.3 of PRC-002-2. The revised wording could be, “. . . satisfies the
same performance criteria given in Part 4.3”. This change makes the
performance requirements of Part 4.3 and Part 4.4 consistent with each other and
subject to changes in the PRC-012-2, rather than independent changes in
another NERC standard.
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Document Name:
Likes:
0
Dislikes:
0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
No
We do not agree that the “single component failure” requirement should apply
to all RAS installed to satisfy TPL performance requirements, by completely
disregarding the severity of adverse system impact resulting from the RAS failure
to operate. In other words, we are advocating that due regard be given to the
RAS classifications/types existing in NPCC, WECC and TRE regions, as well as
the recommended RAS/SPS classifications in the SAMS-SPCS white
paper. Using the RAS nomenclature proposed in the white paper, we
recommend that the “single component failure” requirement be limited to Type PS
(Planning Significant) schemes only. Excluding the Type PL schemes, like the
accepted exclusion for “safety net” (Type ES/EL) schemes, does not necessarily
compromise Adequate Level of Reliability in the BES. We recognize that this
approach will require judicious selection of the demarcation criteria between
Significant (Wide Area) versus Limited (Local) schemes – however, the existing
NPCC and/or WECC demarcation criteria may serve as a reasonably good
starting point. Lastly, we disagree with the claim that Part 4.4 remains
unchanged from the existing R1.3 in PRC-012-0 – although both may have
essentially the same verbiage, the context and the scope of applicability are
widely different. While the existing R1.3 may be rightly interpreted to allow
discretion to the RRO to determine which RAS/SPS “Types” must be subject to
the more robust design that is not degraded by “single component failure”, Part
4.4 takes away that discretion by virtue of being a continent-wide
standard. There is no factual evidence to suggest that the failure-to-operate of
any Local/Limited RAS has resulted in unacceptable/adverse BES performance
to warrant “raising the bar” on applicability of “single component failure”
requirement.
Document Name:
Likes:
0
Dislikes:
0
Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
Likes:
0
Dislikes:
0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Yes
Answer Comment:
Suggest adding clarity to indicate the intent of R4 is not to evaluate the
performance of
the RAS “following” an inadvertent operation since this is covered by R5. The
below statement from
the rationale for R4 can be misinterpreted to imply R4 requires the Transmission
Planner to perform
a technical evaluation “following” an inadvertent operation.
Copied from Rationale for R4:
The purpose of a periodic RAS evaluation is to verify the continued effectiveness
and coordination
of the RAS, as well as to verify that requirements for BES performance following
an inadvertent RAS
operation or a single component failure in the RAS continues to be satisfied.
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
No
Answer Comment:
ATC recommends two modifications to Part 4.4.
One modification is to explicitly include “option c” in the Implementation section of
the Supplemental Material associated with the Standard. The revised wording
could be, “A single component failure in RAS, when the RAS is intended to
operate, or alternative automatic actions back up the failures of single RAS
components . . .” Including text about the alternative option in the standard, rather
than the Supplemental Material would assure that it cannot be dismissed by an
auditor.
The other modification is to remove the unnecessary linking of R4.4 to TPL-001-4
performance requirements with linking to the performance requirements already
expressed in R4.3 of PRC-002-2. The revised wording could be, “. . . satisfies the
same performance criteria given in Part 4.3”. This change makes the
performance requirements of Part 4.3 and Part 4.4 consistent with each other and
subject to changes in the PRC-012-2, rather than independent changes in
another NERC standard.
Document Name:
Likes:
0
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First, placing
this requirement on the Transmission Planner does not conform to the
responsibilities or abilities of the Transmission Planner. While the TP may have
some familiarity with the design of the RAS or with the Operating Procedures
which may be in place, it does not know or need to know the specifics of a single
component failure, just the ramification of an overall RAS operation failure or
inadvertent operation. Currently, the unapproved standard PRC-012-0 and -1
R1.3 contains a single component failure design requirement which is currently
unapproved by FERC and the applicable governmental authorities in
Canada. When these standards were approved by the NERC BOT there was no
NERC BES definition nor was there an approved definition of what a RAS is. We
believe that had the full implication of the costs to be borne by the industry been
recognized and subsequent minimal or no reliability benefit associated with
meeting that requirement for local impact only schemes, the standard would not
have been approved. Further, the System Protection Coordination Subcommittee
of NERC had specifically noted and suggested that 4 types of RAS are on the
BES. Two of these were local and these categories were developed to afford the
SDT to tailor specific and appropriate reliability and security requirements on
these local type schemes. To broadly apply these more stringent requirements to
all RAS on the new BES with the new RAS definition has little cost benefit. In
addition, the existing PRC-012-0 and -1 only require a single component failure
review and design requirement at the time of review. PRC-014-0 and -1, which
are the SPS/RAS assessment standards currently do not require the
Transmission Planner to include a requirement such as Requirement R4 Part 4.4
in their periodic assessment.
The regions should each have a process for ensuring the reliability of the BES
and that the necessary level of reliability and security had been met at the time of
approval. Furthermore, misoperations studies have not indicated that there is a
reliability need to incorporate single component failure design into local
systems. These local RAS which do not meet the requirement would need to be
redesigned, outages taken and then have their revisions made to come into
compliance. This, in and of itself would represent a risk to the operation and
reliability of the BES.
Requirement R4 Part 4.4 currently states;
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐ 001‐ 4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if the SDT is unwilling to remove it
we would propose the following:
4.4 A single component failure in the RAS, when the RAS is intended to operate,
does not result in any of the following conditions on the BES:
o Cascading
o Uncontrolled System Separation
o Instability
The above modification would provide the necessary level of security and
reliability to the BES. Ensuring that RAS installed on the BES or to meet TPL
requirements would only be required when the RAS operation is critical and any
inadvertent operation results in a significant impact to the BES.
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Yes
Answer Comment:
Please affirm this understanding: For single component failure, a RAS must still
satisfy System performance requirements.
Document Name:
Likes:
0
Dislikes:
0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First, placing
this requirement on the Transmission Planner does not conform to the
responsibilities or abilities of the Transmission Planner. While the TP may have
some familiarity with the design of the RAS or with the Operating Procedures in
place, they do not know or need to know the specifics of a single component
failure. The TP just needs to know the ramifications of an overall RAS operation
failure or inadvertent operation. Currently, standards PRC-012-0 and PRC-012-1
R1.3 contain a single component failure design requirement. When these
standards were approved by the NERC BOT, there was no NERC BES definition
nor was there an approved definition of a RAS. We believe that had the full
implication of the costs to be borne by the industry and the subsequent minimal or
no reliability benefit associated with this (local impact only schemes) had been
recognized, the standard would not have been approved by the NERC
BOT. Further, the System Protection Coordination Subcommittee of NERC had
specifically noted and suggested that 4 types of RAS are on the BES. Two of
these types were local and these categories were developed to allow the SDT to
tailor specific and appropriate reliability and security requirements on these local
type schemes. To broadly apply these more stringent requirements to all RAS on
the new BES with the new RAS definition has no cost benefit. In addition, PRC012-0 and PRC-012-1 only require a single component failure review and design
requirement at the time of review. PRC-014-0 and PRC-014-1, which are the
SPS/RAS assessment standards, currently do not require the Transmission
Planner to include a requirement such as Requirement R4 Part 4.4 in their
periodic assessment. The SDT has gone, in our view, unnecessarily beyond the
intent of the current standards in this regard.
In addition, it should be noted that all existing RAS have gone through regional
reviews and been approved for implementation. These existing RAS may not
have met the existing single component failure requirement due to the revision of
the BES. The regions each have a process for ensuring the reliability of the BES
and the necessary level of reliability and security has been met at the time of
approval. Furthermore, misoperations studies have not indicated that there is a
reliability need to incorporate single component failure design into local
systems. These local RAS, which do not meet the requirement, would need to be
redesigned, undergo outages, and then have revisions made to bring them into
compliance. This, in and of itself would represent a risk to the operation and
reliability of the BES.
Requirement R4 Part 4.4 currently states:
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐ 001‐ 4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if the SDT is unwilling to remove it,
we propose the following:
“4.4 A single component failure in the RAS, when the RAS is intended to operate,
does not result in any of the following conditions on the BES:
Cascading
Uncontrolled System Separation
Instability”
The above modification would provide the necessary level of security and
reliability to the BES. This ensures that RAS installed on the BES or installed to
meet TPL requirements would only be required to meet Part 4.4 when the RAS
operation is critical and any inadvertent operation results in a significant impact to
the BES.
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Kiguel - David Kiguel - 8 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Yes
Answer Comment:
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Document Name:
Likes:
0
Dislikes:
0
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First, placing
this requirement on the Transmission Planner does not conform to the
responsibilities or abilities of the Transmission Planner. The TP, although may
have some familiarity with the design of the RAS or with the Operating
Procedures which may be in place does not know or need to know the specifics
of a single component failure, just the ramification of an overall RAS operation
failure or inadvertent operation. Currently, the unapproved standard PRC-012-0
and -1 R1.3 contains a single component failure design requirement which is
currently unapproved by FERC and the applicable governmental authorities in
Canada. When these standards were approved there was no NERC BES
definition nor was there an approved definition of what a RAS is. We believe that
had the full implication of the costs to be borne by the industry been recognized
and subsequent minimal or no reliability benefit associated with meeting that
requirement for local impact only schemes, the standard would not have been
approved. Further, the System Protection Coordination Subcommittee of NERC
had specifically noted and suggested that 4 types of RAS are on the BES. Two of
these were local and these categories were developed to afford the SDT to tailor
specific and appropriate reliability and security requirements on these local type
schemes. To broadly apply these more stringent requirements to all RAS on the
new BES with the new RAS definition has no cost benefit. In addition, the
existing PRC-012-0 and -1 only require a single component failure review and
design requirement at the time of review. PRC-014-0 and -1, which are the
SPS/RAS assessment standards currently do not require the Transmission
Planner to include a requirement such as Requirement R4 Part 4.4 in their
periodic assessment. The SDT has gone, in our view, unnecessarily beyond the
intent of the current standards in this regard.
In addition it should be noted that all existing RAS have gone through regional
reviews and been approved for implementation. These existing RAS may not
have met the existing single component failure requirement due to the revision of
the BES. The regions each have a process for ensuring the reliability of the BES
and that the necessary level of reliability and security had been met at the time of
approval. Furthermore, misoperations studies have not indicated that there is a
reliability need to incorporate single component failure design into local
systems. These local RAS which do not meet the requirement would need to be
redesigned, outages taken and then have their revisions made to come into
compliance. This, in and of itself would represent a risk to the operation and
reliability of the BES.
Requirement R4 Part 4.4 currently states;
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐ 001‐ 4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if the SDT is unwilling to remove it
we would propose the following:
4.4 A single component failure in the RAS, when the RAS is intended to operate,
does not result in any of the following conditions on the BES:
o Cascading
o Uncontrolled System Separation
o Instability
The above modification would provide the necessary level of security and
reliability to the BES. Ensuring that RAS installed on the BES or to meet TPL
requirements would only be required when the RAS operation is critical and any
inadvertent operation results in a significant impact to the BES.
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
No
Answer Comment:
Dominion believes that redundancy should not be required for a RAS designed
for events such as TPL-001-4 P4 (stuck breaker) or P5 (relay failure event). The
design should not have to consider two failures which is improbable. As an
analogy, in places where there is no RAS scheme, there is no requirement to test
a P4 stuck breaker event and then assume that the breaker failure relay does not
work, essentially combining P4 and P5 together. Designing a redundant RAS for
breaker failure could require installation of two breaker failure relays per breaker
to initiate the RAS and maintain complete redundancy. This leads to excessive
complexity which can hurt reliability.
Additionally, Dominion suggest adding clarity to indicate the intent of R4 is not to
evaluate the performance of the RAS “following” an inadvertent operation since
this is covered by R5. The rationale statement for R4 can be misinterpreted to
imply R4 requires the Transmission Planner to perform a technical evaluation
“following” an inadvertent operation.
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Answer Comment:
No comment
Document Name:
Likes:
4
Dislikes:
0
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First, placing
this requirement on the Transmission Planner does not conform to the
responsibilities or abilities of the Transmission Planner. The TP may have some
familiarity with the design of the RAS or with the Operating Procedures which
may be in place, but does not know or need to know the specifics of a single
component failure, just the ramification of an overall RAS operation failure or
inadvertent operation. Currently, Part R1.3 of standards PRC-012-0 and -1
contains a single component failure design requirement. When these standards
were approved by the NERC BOT there was no NERC BES definition nor was
there an approved definition of what a RAS is. We believe that had the full
implication of the costs to be borne by the industry been recognized and
subsequent minimal or no reliability benefit associated with meeting that
requirement for local impact only schemes, the standard would not have been
approved by the NERC BOT. Furthermore, the System Protection Coordination
Subcommittee of NERC had specifically noted and suggested that 4 types of RAS
are on the BES. Two of these were local and these categories were developed to
afford the SDT to tailor specific and appropriate reliability and security
requirements on these local type schemes. To broadly apply these more
stringent requirements to all RAS on the new BES with the new RAS definition
has little cost benefit. In addition, the existing PRC-012-0 and -1 only require a
single component failure review and design requirement at the time of
review. PRC-014-0 and -1, which are the SPS/RAS assessment standards
currently do not require the Transmission Planner to include a requirement such
as Requirement R4 Part 4.4 in their periodic assessment. The SDT has gone
unnecessarily beyond the intent of the current standards in this regard.
In addition it should be noted that all existing RAS have gone through regional
reviews and been approved for implementation. These existing RAS may not
have met the existing single component failure requirement due to the revision of
the BES. The regions each have a process for ensuring the reliability of the BES,
and that the necessary level of reliability and security had been met at the time of
approval. Furthermore, misoperation studies have not indicated that there is a
reliability need to incorporate single component failure design into local
systems. These local RAS which do not meet the requirement would need to be
redesigned, outages taken, and then revisions made to come into
compliance. This, in and of itself would represent a risk to the operation and
reliability of the BES.
Requirement R4 Part 4.4 currently states;
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐ 001‐ 4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if not removed, we propose the
following:
4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not result in any of the following conditions on the
BES:
o Cascading
o Uncontrolled System Separation
o Instability
The above modification would provide the necessary level of security and
reliability to the BES. Ensuring that RAS installed on the BES or installed to meet
TPL requirements would only be required when the RAS operation is critical, and
any inadvertent operation results in a significant impact to the BES.
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Yes
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
No
Answer Comment:
Single component failures should exclude station dc supply and some portions of
communications systems (e.g., microwave towers and multiplexing
equipment). Such exceptions have existed in the industry.
For a single component failure, it is unclear why the requirement was changed
from simply having to meet the performance requirements defined in TPL
standards to having to meet those required for the events and conditions for
which the RAS is designed.
In the Q & A document, section 5, page 4, how can arming excess load and
generation not impact reliability? TPL footnote 9 notes that “the planning process
should be to minimize the likelihood and magnitude of interruption.” RAS entities
should be allowed to consider whether a 100% chance of tripping too much
load/generation in the event of correct RAS operation really meets the intent of
TPL. In some cases, allowing a single point failure to degrade the performance of
the RAS is a better overall choice for minimizing total probability of interruption.
In the Q & A document, section 5, page 4, what kind of automatic actions are
referenced? As the NERC reliability standards have evolved, the classification of
RAS has expanded from just very high complexity protection schemes to now
include many kinds of routine automatic actions. Almost any automatic action
used to mitigate a TPL violation would become a RAS by virtue that it is used to
meet requirements identified in a NERC Reliability Standard.
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
No
Answer Comment:
At the present time there are RAS in service that have a limited local impact. To
universally apply the same design criteria to all RAS regardless of their impact on
BES in case of failure to operate may have no cost benefit in the case of the RAS
installed to address local problems.
We propose the following to be included in the standard:
The failure of a RAS to operate does not result in any of the following conditions
on the BES:
1.
Cascading
2.
Uncontrolled System Separation
3.
Instability
When the criteria mentioned above is not met a redundant design will be
required.
When a RAS is used to respond to an event, e.g. category P1 in TPL-001-4, its
failure should be considered to be a more severe event, just as in TPL-001-4 the
failure of a breaker or protection relay following a P1 event is recognized as
“Multiple Contingency” (category P3 and P4). For this reason, the system
performance with a RAS failure should not be required to meet the same
requirements (defined in TPL-001-4) as those for the original event.
We suggest that the system performance requirement in case of failure of a
single component of a RAS be limited to the following:
1.
The BES shall remain stable
2.
Cascading or Uncontrolled System Separation shall not occur
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Yes
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Document Name:
Likes:
0
Dislikes:
0
Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Gallo - Austin Energy - 6 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
When a RAS is used to respond to an event, e.g. category P1 in TPL-001-4, its
failure should be considered to be a more severe event, just as in TPL-001-4 the
failure of a breaker or protection relay following a P1 event is recognized as
“Multiple Contingency” (category P3 and P4). For this reason, the system
performance with a RAS failure should not be required to meet the same
requirements (defined in TPL-001-4) as those for the original event.
We suggest that the system performance requirement in case of failure of a
single component of a RAS be limited to the following:
1.
The BES shall remain stable
2.
Cascading or Uncontrolled System Separation shall not occur
Please also see the following comments for relaxing the requirements for a class
of RAS.
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
No
Answer Comment:
We recommend that the SDT consolidate the numerous sub-parts in Requirement
R4, as they are confusing to both registered entity and auditor.
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Requirements R6 and R7 pertain to the development and implementation of Corrective Action
Plans (CAPs). Question 5 addresses these requirements.
5. Corrective Action Plans: Do you agree that the application of Requirements R6 and R7 would
address the reliability objectives associated with CAPs? If no, please provide the basis for your
disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
No
Answer Comment:
We suggest that the RAS-owner be removed from the Requirements, and that
only the RAS-entity be subject to these Requirements. See below for more
comments.
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
No
Answer Comment:
AEP believes R6 should be further revised to clarify exactly when the “six
calendar months” begins. We suggest revising it to state ”Within six‐full‐calendar
months of *the RC* being notified of a deficiency…”
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
No
Answer Comment:
The NSRF recommends revising R6 to explicitly include the Planning Coordinator
with working like, “. . . submit the CAP to its reviewing Reliability Coordinator and
impacted Transmission Planners and Planning Coordinators”. The inclusion of
Transmission Planners and Planning Coordinators is appropriate because these
entities will generally have the best planning horizon information and expertise to
review the CAP.
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
There appears to be a gap between R6 and R7, from the point where each RAS
owner submits a CAP to its RC, and then implementing the CAP. There should be
a requirement placed upon the RC where a review of the CAP is completed and
feedback provided to the RAS owner.
Document Name:
Likes:
0
Dislikes:
0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
No
Answer Comment:
The requirement R7 is very ambiguous about the time-frame for implementing a
corrective action plan. Who approves the proposed schedule?
Document Name:
Likes:
0
Dislikes:
0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
No
Answer Comment:
R6 and R7 should specify a CAP is created only if deficiency is on the RASowners part of the RAS. As written, all RAS-owners would be responsible for
submitting CAPs if a single deficiency was identified on just one part of the
RAS. As written, a RAS-owner would be responsible for writing a CAP and
implementing the CAP for something they may have no control over, if the
deficiency is on another RAS-owners part of the RAS.
Document Name:
Likes:
0
Dislikes:
0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Although the Corrective Action Plan (CAP) does address the reliability objectives
it is unclear on the responsibilities of the parties involved. As the requirement is
written, the Owner must submit the corrective action plan. There is a little
confusion on any RAS that have multiple owners. Would ALL the owners need to
submit a CAP or only the owner of the equipment in question? SRP recomends
clarifying and possibly designating operator as the one to submit the CAP.
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
Likes:
0
Dislikes:
0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
No
Answer Comment:
ATC recommends revising R6 to explicitly include the Planning Coordinator with
working like, “. . . submit the CAP to its reviewing Reliability Coordinator and any
applicable Planning Coordinators”. The inclusion of Planning Coordinators is
appropriate because Planning Coordinators will generally have the best
information and expertise to review the CAP.
Document Name:
Likes:
0
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
Requirement R6 reads as follows:
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner shall
participate in developing a Corrective Action Plan (CAP) and submit the CAP to
its reviewing Reliability Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS-owner and only
states they shall participate. Standard requirements need to be specific on who is
responsible for what, and when. We also suggest that any CAP being submitted
to the PC (we feel that the PC is appropriate as discussed in comments on R1)
be a “mutually agreed upon” CAP. To address this issue we suggest the
following:
Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to
Requirement R4 or Requirement R5, each RAS‐ owner shall develop a mutually
agreed upon
Corrective Action Plan (CAP) with all affected Reliability Coordinators and submit
the CAP to its reviewing Planning Coordinator(s).
We suggest that the full responsibility of the development of the CAP rest with the
RAS-entity. The rationale box states this but it needs to be clear in the
requirement. Irrespective of complexity, the need to collaborate with others and
hire consulting services, the responsibility should rest solely on the RAS-owner.
Also there may be a need for an additional requirement to notify the PC and TOP
when the CAP has been completed, and the RAS is performing correctly. We will
leave this for consideration by the SDT and believe this brings specific closure to
any RAS deficiency.
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
No
Answer Comment:
As mentioned in our previous comments, Peak recognizes that the RC or TOP
may impose operating restrictions to ensure reliability until the RAS deficiency is
resolved but maintains that the CAP should be reviewed by an independent party
to assure that it addresses the reliability issues in a reasonable timeframe. . For
example, a CAP could be created with an unreasonable timeframe that
unnecessarily extends a reliability issue. This independent review by the RC and
subsequent required action by the RAS-entity exists for new RAS but not for
CAPs, which appears inconsistent with the intent of the Standard. A process
similar to that described in R2 and R3 should also apply to CAPs and not just new
and functionally modified RAS.
Document Name:
Likes:
0
Dislikes:
0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
We suggest the following rewording:
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner shall
develope a Corrective Action Plan (CAP) and submit the CAP to its reviewing
Reliability Coordinator(s).”
R6 should reflect that it is either solely the RAS owner’s responsibility or both the
RC and RAS owner must have responsibility and “participate” in developing the
CAP together. If the CAP requires mutual participation to develop, then both
parties (the RAS owner AND the RC) must have compliance responsibility.
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
No
Answer Comment:
Reclamation suggests that the RAS-entity should be responsible for the
Corrective Action Plans (CAPs) called for in requirements R6 and R7. Each
RAS-owner should not be responsible for developing CAPs and coordinating
them with the Reliability Coordinator (RC) because this could result in duplication
of efforts or inconsistent corrective actions. As outlined in the Technical
Justifications, “[t]he purpose of the RAS-entity is to be the single information
conduit with each reviewing Reliability Coordinator (RC) for all RAS-owners for
each RAS.” When there are several owners involved in a RAS, the RC should
communicate with the RAS-entity as one point of contact to ensure that an overall
CAP addresses any RAS deficiencies.
Document Name:
Likes:
0
Dislikes:
0
David Kiguel - David Kiguel - 8 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
No
Answer Comment:
The SRC agrees that the RAS entity should develop Corrective Action Plans to
evaluate RASs to address issues and/or deficiencies identified by their
evaluations, but would suggest that such entities be required to provide the
Corrective Action Plans to their Reliability Coordinator and Planning
Coordinator for review.
Document Name:
Likes:
0
Dislikes:
0
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
Answer Comment:
No
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner shall
participate in developing a Corrective Action Plan (CAP) and submit the CAP to
its reviewing Reliability Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS-owner and only
states they shall participate. Standard requirements need to be specific on who is
responsible for what, and when. We also suggest that any CAP being submitted
to the RC be a “mutually agreed upon” CAP. To address this issue we suggest
the following:
Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner shall develop
a mutually agreed upon Corrective Action Plan (CAP) with all affected Reliability
Coordinators and submit the CAP to its reviewing Reliability Coordinator(s).
We suggest that the full responsibility of the development of the CAP rest with the
RAS-owner. The rationale box states this but it needs to be clear in the
requirement. Irrespective of complexity, the need to collaborate with others and
hire consulting services, the responsibility should rest solely on the RAS-owner.
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Attachment 1, Section III-Implementation states, “5. Documentation describing
the functional testing process.” Dominion recommends deleting this bullet. This
information is not necessarily available during the preliminary design phase. The
approval of the design is sought prior to detailed engineering. (Planning)
In R5 it states that the RAS owner analyzes the event, but in flow chart it states
RAS owner and TP. Dominion suggests that the content in the Flow Chart be
consistent with language of the Requirement.
R5 references the timeframe “within 120 calendar days”, however in other areas
of the document the time frame is stated to be “within XX calendar
months”. Dominion suggests updating the document to reflect the actual
timeframe. Dominion also believes clarification is needed to establish “full
calendar months” versus “months”.
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
No
Answer Comment:
See the comments in #2, which is critical to R6. Furthermore, the team should
modify the R6 phrase as shown below:
“…each RAS-owner shall participate in developing a Corrective Action Plan with
the RAS-entity which shall and submit the CAP to its reviewing Reliability
Coordinator….”
This will result in one RAS-entity submitted CAP to the reviewing RC.
Document Name:
Likes:
4
Dislikes:
0
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
No
Answer Comment:
Requirement R6 reads as follows:
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner shall
participate in developing a Corrective Action Plan (CAP) and submit the CAP to
its reviewing Reliability Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS-owner and only
states they shall participate. Standard requirements need to be specific on who is
responsible for what, and when. We also suggest that any CAP being submitted
to the RC be a “mutually agreed upon” CAP. To address this issue we suggest
the following:
Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner and affected
Reliability Coordinator(s) shall develop a mutually agreed upon Corrective Action
Plan (CAP) and submit the CAP to its reviewing Reliability Coordinator(s).
Also, there may be a need for an additional requirement to notify the RC and TOP
when the CAP has been completed, and the RAS is performing correctly. This
should be considered by the SDT. This brings specific closure to any RAS
deficiency.
Requirement R5 stipulates that the RAS-owner identifies deficiencies to its
reviewing RC. Suggest R6 be revised to read:
“Within six-full-calendar months of identifying or of being notified of a…”
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
No
Answer Comment:
TANC has concerns with the current language in R5, R6, and R7, because it
appears these requirements would assign the same or similar responsibilities to
“each RAS-owner” when a single RAS operates or fails to operate as
expected. In circumstances where a single RAS has multiple RAS-owners, the
current language would potentially create overlapping responsibilities to analyze
the RAS performance and develop/implement a Corrective Action Plan. It seems
that these responsibilities established in R5, R6, and R7 would be more
appropriately assigned to the single RAS-entity for a RAS rather than to each
RAS-owner.
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
No
Answer Comment:
Requirement R6 reads as follows:
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to
Requirement R4 or Requirement R5, each RAS‐ owner shall participate in
developing a
Corrective Action Plan (CAP) and submit the CAP to its reviewing Reliability
Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS-owner and only
states they shall participate. Standard requirements need to be specific on who is
responsible for what, and when. We also suggest that any CAP being submitted
to the RC be a “mutually agreed upon” CAP. To address this issue we suggest
the following:
Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to
Requirement R4 or Requirement R5, each RAS‐ owner shall develop a mutually
agreed upon
Corrective Action Plan (CAP) with all affected Reliability Coordinators and submit
the CAP to its reviewing Reliability Coordinator(s).
We suggest that the full responsibility of the development of the CAP rest with the
RAS-owner. The rationale box states this but it needs to be clear in the
requirement. Irrespective of complexity, the need to collaborate with others and
hire consulting services, the responsibility should rest solely on the RAS-owner.
Requirement R6 states, “Within six‐ full‐ calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or Requirement R5…”,
however, a notification does not come out of R5 since the applicability to both R5
and R6 is with the RAS owner.
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
No
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Document Name:
Likes:
0
Dislikes:
0
Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Gallo - Austin Energy - 6 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
No
Answer Comment:
Texas RE is concerned there could be an extended time frame where a RAS with
a known deficiency will be in service since the requirement to develop a
Corrective Action Plan (CAP) is do so within six months. Texas RE is also
concerned there is no defined time frame for implementing the CAP.
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
No
Answer Comment:
The RC needs to be given the authority to reject the CAP, or suggest changes to
the CAP.
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
Hydro One Networks Inc. believes that as quoted below, R6 does not clearly
assign the responsibility to the RAS-owner and only states that they “shall
participate”.
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirement R4 or Requirement R5, each RAS‐ owner shall
participate in developing a Corrective Action Plan (CAP) and submit the CAP to
its reviewing Reliability Coordinator(s).”
Standard requirements need to be specific on as to who is responsible for what,
and when. We also suggest that any CAP being submitted to the RC be a
“mutually agreed upon” CAP. To address these issues, we suggest revising the
wording to read the following:
“Within six‐ full‐ calendar months of being notified of a deficiency in its RAS
pursuant to Requirements R4 and R5 state that each RAS‐ owner shall develop
with all affected RCs, a mutually agreed upon Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s)”. However, Hydro One
Networks Inc. suggests that the full responsibility of the development of the CAP
rest with the RAS-owner. The rationale box states that the full responsibility of
the development of the CAP rests with the RAS-owner, but this needs to be clear,
and explicitly stated in the requirement as well. Irrespective of complexity, the
need to collaborate with others, hire consulting services, etc., the responsibility
should rest solely on the RAS-owner.
Requirement R6 states, “Within six‐ full‐ calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or Requirement R5…”,
however, Hydro One would like to point out that a notification does not result from
requirement R5 since the applicability to both R5 and R6 is with the RAS owner
themselves.
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
No
Answer Comment:
The RAS-entity should be included in Requirements R6 and R7 in a coordinating
role between the RAS-owners and the TP and/or RC. It should be made clear that
the RAS-owners are only responsible for their portion of the RAS.
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
No
Answer Comment:
We disagree with the SDT that there needs to be two requirements to cover
CAPs. These requirements should be consolidated and simplified to avoid
unnecessary confusion and potential compliance impacts. Furthermore, CAPs
are administrative in nature and we recommend removing these requirements
under Paragraph 81 Administrative criteria.
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
6. Implementation Plan: Do you agree with the Implementation Plan? If no, please provide the
basis for your disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
No
Answer Comment:
The requirement R7 is very ambiguous about the time-frame for implementing a
corrective action plan. Who approves the proposed schedule?
Document Name:
Likes:
0
Dislikes:
0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
No
Answer Comment:
SRP notices possible confusion on the implementation for R4 and R8. The
rationale for R4 and R8 state that the 60 month time period begins on the
effective date of the standard. However, the implementation plan does not state
that similarly. There is potential confusion for this as many entities are likely to
attempt to have their evaluations and functional tests completed by the effective
date.
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
Likes:
0
Dislikes:
0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Yes
Answer Comment:
Peak interprets the Implementation Plan as grandfathering in all existing RAS,
which means review and approval of existing RAS is not required – only for new
or modified RAS. The revised Standard does not address existing RAS, and
therefore neglects any potential reliability issues associated with them. Peak
seeks clarity on this issue.
Document Name:
Likes:
0
Dislikes:
0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Kiguel - David Kiguel - 8 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
No
Answer Comment:
The Implementation Plan should be modified to include clarification for
implementation of R4. TFSP suggests adding the language used in the Rationale
box for R4, which says: “Sixty‐ full‐ calendar months, which begins on the
effective date of the standard pursuant to the implementation plan…”
The standard or the Implementation Plan should allow the RAS-owner sufficient
time to mitigate a design deficiency identified as part of R4, such as the lack of
redundancy without removing the RAS from service. Clarification should be
provided to allow for continued operation of an existing RAS after a single
component failure scenario is identified until a Corrective Action Plan can be
completed.
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
No
Answer Comment:
The effective date in Implementation Plan should be increased from 12 month to
36 months after the first day of the first calendar quarter after the date the
standard is approved. This reason for this delay is that standard establishes a
new working framework between RAS-owners, RAS-entities, TPs, and RCs. That
itself will involve considerable start-up effort. In return for this added delay, the
first periodic review of each RAS under R4 could be due within 36 months, with
subsequent reviews every 60 months.
Document Name:
Likes:
4
Dislikes:
0
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
No
Answer Comment:
The Implementation Plan should be modified to include clarification for
implementation of R4. Suggest adding the language used in the Rationale for
Requirement R4, which says: “Sixty‐ full‐ calendar months, which begins on the
effective date of the standard pursuant to the implementation plan…”
The standard or the Implementation Plan should allow the RAS-owner sufficient
time to mitigate a design deficiency identified as part of R4, such as the lack of
redundancy without removing the RAS from service. Clarification should be
provided to allow for continued operation of an existing RAS after a single
component failure scenario is identified until a Corrective Action Plan can be
completed.
The Implementation Plan should address the possible scenario of a RAS
misoperation occurring within 120 days of the Standard’s effective date, and if R5
would apply. Would this misoperation require the development of a CAP after the
effective date of the Standard? This would apply for R6 and R7 as well.
For testing records will the RAS-owner need to have documentation of testing
prior to the standard’s effective date? This should be clarified in the
Implementation Plan.
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Answer Comment:
N/A
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
No
Answer Comment:
In the Implementation Plan, page 2, the following sentence has a
grammatical/mechanical issue: “As of the date of posting of this Implementation
Plan, however, the Commission has not issued an Final Order approving and
retirement the Reliability Standards enumerated above.”
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
No
Answer Comment:
The Implementation Plan should allow the RAS-owner sufficient time to mitigate a
design deficiency identified as part of R4, such as the lack of redundancy without
removing the RAS from service. Clarification should be provided to allow for
continued operation of those RAS, that are already in service when the standard
becomes effective, after a single component failure scenario is identified until a
Corrective Action Plan can be completed.
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Gallo - Austin Energy - 6 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
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0
Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
The Implementation Plan should be modified to include clarification for
implementation of R4. Hydro One Networks Inc. agrees with the NPCC’s TFSP
in adding the language used in the Rationale box for R4, which says: “Sixty‐ full‐
calendar months, which begins on the effective date of the standard pursuant to
the implementation plan…”
The standard or the Implementation Plan should allow the RAS-owner sufficient
time to mitigate a design deficiency identified as part of R4, such as the lack of
redundancy without removing the RAS from service. Clarification should be
provided to allow for continued operation of an existing RAS after a single
component failure scenario is identified until a Corrective Action Plan can be
completed.
Document Name:
Likes:
0
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0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Yes
Answer Comment:
The Implementation Plan should specify when the first 5 year evaluation required
by R4 should be completed for an existing RAS.
Document Name:
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0
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0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
No
Answer Comment:
We ask the SDT to clarify whether the approval process and the first technical
evaluation needs to be performed before or after the effective date of the
standard.
Document Name:
Likes:
0
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0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
7. If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RFC
Selected Answer:
Answer Comment:
We suggest that the standard have applicability to only the RAS entity, normally
the primary Transmission Owner for the region affected. Including more than one
party will make this standard too cumbersome and difficult to manage. The
primary application of a RAS is to multi-facility, wide-area disturbances and as
such is best vested in the Transmission Owner, who has a wider “system”
viewpoint than the Generator Owner. We are concerned that Generator Owners
may become inadvertent RAS-owners simply by owning a small fraction of the
equipment needed for the RAS, and thus become subject to requirements R5
through R8, when they are typically passive parties to the RAS.
Document Name:
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0
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0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
na
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
na
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
For R5, we propose revised wording that “within 120 days, or on a mutually agree
upon schedule.” This would allow earlier or later completion of the analysis when
warranted by unusual circumstances.
Document Name:
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0
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0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
With regards to R5:
What is the benefit of providing the reviewing RC with results of a successful RAS
operation?
With regards to R8:
Although functional testing would verify that the scheme is working as designed,
there is no reason to believe that an RAS is any different from another protection
system i.e., it would need to be tested at intervals outside the normal
maintenance program. The testing of RAS should fall in line with PRC-005-3
requirements for monitored systems and unmonitored systems.
By requiring “at least once every six calendar years, each RAS‐ owner shall
perform a functional test,” the drafting team is forcing all owners of a RAS that
has any Protection Systems in it to abandon the PRC-005-3 12 year Maximum
Maintenance Intervals allowed in tables 1-1, 1-2, 1-3, 1-5, and 4.
If Requirement R9 is adopted as stated in this draft of the standard, each
segment of a RAS would have to be tested at a maximum interval of 6 calendar
years. This would require, for example, that voltage and current sensing devices
providing inputs to protective relays of a RAS “shall” be tested “at least once
every six calendar years” instead of 12 Calendar years allowed in Table 1-3 of
PRC-005-3.
Document Name:
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0
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0
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC
Group Information
Group Name:
Seattle City Light Ballot Body
Group Member Name Entity
Region
Segments
Pawel Krupa
Seattle City Light
WECC
1
Dana Wheelock
Seattle City Light
WECC
3
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Voter Information
Voter
Segment
Ginette Lacasse
1,3,4,5,6
Entity
Region(s)
Seattle City Light
WECC
Selected Answer:
Answer Comment:
1. We ask for a clarification on the PRC-012-2 definition of RAS Owner to only
“exclusively” include the owner of the scheme, and not include a “participating”
entity in the RAS operation. The participating entity equipment would be covered
by other standards such PRC-005-2 and thus should be excluded from standard.
2. The requirement R8 will require that the RAS is tested every 6 years, which is
equivalent to any unmonitored relays that we have under PRC-005. However,
testing the RAS may prove to be more laborious since it will most likely require
coordination among multiple participating entities, so a more relaxed test
sequence (12 years) would be preferred.
Document Name:
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0
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0
Chris Scanlon - Exelon - 1 Group Information
Group Name:
Exelon Utilities
Group Member Name Entity
Region
Segments
Chris Scanlon
BGE, ComEd, PECO TO's
RFC
1
John Bee
BGE, ComEd, PECO LSE's
RFC
3
Voter Information
Voter
Segment
Chris Scanlon
1
Entity
Region(s)
Exelon
Selected Answer:
Answer Comment:
Document Name:
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0
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0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Answer Comment:
RAS-entity should be responsible for R5 instead of RAS-owner. The RAS-entity,
being designated to represent all RAS-owners, is in the best position to evaluate
the operation of a RAS.
RAS-entity should be responsible for R8 functional testing.
R9 should include a sub-requirement for RCs to share their database with
neighboring RCs to provide coordination of RAS schemes near RC borders.
Document Name:
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0
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0
Jeffrey Watkins - Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway - NV
Energy, 5
Selected Answer:
Answer Comment:
There are numerous references to components of a RAS scheme in the standard
and supplemental material, but there is no clear definition of what constitutes a
component of a RAS scheme. A lack of a clear definition can lead to different
interpretations of what a RAS component is. For example, Requirement R4.3
requires that “the possible inadvertent operation of the RAS resulting from any
single RAS component malfunctions satisfies all of the following” conditions in
4.3.1 thru 4.3.5. While it is implied that the RAS components could include
elements such as the RAS controller, communications, control circuitry,
supervisory relays or functions (breaker 52A contact), and/or voltage or current
sensing devices, it is not clearly stated. This leaves it open for some entities to
possibly consider additional items such as a circuit breaker as a RAS component
and other entities to not consider it. It could also allow some entities to take a
more relaxed approach and exclude components that should possibly be
included. A definition or explanation of RAS components should be added to the
standard similar to the definitions used in PRC-005-4 (i.e. Automatic Reclosing
and Sudden Pressure Relaying).
Document Name:
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0
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0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Answer Comment:
Currently as the standard is written, R5 and R6 require each RAS-owner to
submit the results of the analysis and a CAP if needed. Tri-State does not believe
it should be required that each RAS-owner submit the results and/or CAP rather
than the RAS-entity. The RAS-entity can collect the results and submit 1
report/CAP, instead of several individual submittals from the seperate RASowners.
Also, Tri-State believes there is a numbering issue in Section II of Attachment 1 of
the standard. It looks like "Documentation showing that the possible inadvertent
operation of the RAS resulting from any singles RAS component malfunction
satisfies all of the following:" should be #5 since it is a separate topic from #4.
Document Name:
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0
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0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
a.
The Rationale Box for R6 states that the “RAS-owner” will need to submit
information in Attachment 1 to the RC, should this be the RAS-entity?
b.
In R6, if the RAS-owner is the entity that performed the analysis in R4 of
R5, when does the 6 month clock start (i.e., when was it notified)?
c.
For R7, is the intent that each RAS-owner update the CAP with the RC? It
seems like this should be the job of the RAS-entity, not multiple RAS-owners.
Document Name:
Likes:
0
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0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Molly Devine - IDACORP - Idaho Power Company - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Joshua Andersen - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
As written the rationale for R8 is not incorporated into the requirement. R8
rationale states that correct operation of a RAS segment would qualify as a
functional test. Please state that in the requirement so there is no confusion or
debate if a correct operation resets the time frame necessary to perform a test.
SRP recommend the removal of the word “Requirement” in front of any R#
designation. R1 stands for Requirement 1 and is sufficient. Saying "Requirement
R1" is like saying Requirement Requirement 1. Also, the term “Requirement” is
not a defined term.
Document Name:
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0
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0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Answer Comment:
Please refer to RSC-NPCC comments which Hydro-Quebec TransEnergie
supports.
Document Name:
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0
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0
David Greene - SERC - 1,10 - SERC
Group Information
Group Name:
SERC PCS
Group Member Name Entity
Region
Segments
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Voter Information
Voter
Segment
David Greene
1,10
Entity
Region(s)
SERC
SERC
Selected Answer:
Answer Comment:
If a RAS has multiple owners, and one or more owners is not compliant to R8,
does this mean that all owners, or the RAS-entity, are non-compliant?
Document Name:
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0
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0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
IMEA questions the need to include DP in the applicability. It is likely a DP will
only own a part of a RAS. It should be adequate to specify TO coordination to
verify RAS performance.
In R8, IMEA recommends deletion of "...and the proper operation of nonProtection System components."; i.e., it should be adequate to indicate only
"...verify overall RAS performance."
Document Name:
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0
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0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Answer Comment:
For R5, ATC proposes revising wording that “within 120 days, or on a
mutually agree upon schedule.” This would allow earlier or later
completion of the analysis when warranted by unusual circumstances.
The purpose of Version 2 of PRC-005 was to consolidate all maintenance
and testing of relays under one Standard. Having RAS testing within
PRC-012-2 would be contrary to that end. ATC addresses this concern
as follows:
Functional testing of RAS (as stated in Requirement 8 of PRC-012-2) is a
maintenance and testing activity that would be better included in the PRC-005
standard. The present PRC-005-2 Reliability Standard is the maintenance
standard that replaces PRC-005-1, 008, 011 and 017 and was designed to cover
the maintenance of SPSs/RASs. However, Reliability Standard PRC-005-2 lacks
intervals and activities related to non-protective devices such as programmable
logic controllers. ATC recommends that a requirement for maintenance and
testing of non-protective RAS components be added to a revision of PRC-005-2,
rather than be an outlying maintenance requirement located in the PRC-012-2
Standard.
Document Name:
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0
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0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Answer Comment:
Regarding the rationale for Requirement R8--We agree with segmented
testing. However, the requirement does not state this and implies an overall test
should still be performed.
R8 currently states:
At least once every six‐ calendar years, each RAS‐ owner shall perform a
functional test of each RAS to verify the overall RAS performance and the proper
operation of non-Protection System components.
Suggest revising to:
At least once every six‐ calendar years, each RAS‐ owner shall perform a
functional test of each RAS to verify the overall RAS performance and the proper
operation of non-Protection System components. This test can be either:
o An end to end test encompassing all components and testing actual
functionality
o A segmented test to test all the components by grouping them together into
blocks until all parts of the RAS have been tested
Additional information in the Technical Guideline may be required to explain how
the six year cycle is measured when allowing segmented testing. Segmented
testing can test all components of an RAS every six years, but an individual
component could end up being tested once every 10 years. For example, a RAS
is designed so that it is comprised of a segment “A”, and a segment
“B”. Segment “A” is tested in year 1, segment “B” is tested in year 5. As per
Requirement R8 the RAS has been tested within “six-calendar years.” The clocks
starts for the next functional test period, and segment “B” is tested in year 1 (one
year since its first test), and segment “B” tested in year 5 (nine years since its first
test). The RAS was tested within the “six-calendar years”, but segment “B” had a
nine year interval. The requirement should be modified to state that all
segments shall be tested in the same calendar year.
The RAS-owner should be included in Attachment 3.
Document Name:
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0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Answer Comment:
Peak was unable to locate the “consideration of comments” after the last round of
comments posted on the NERC website. The “consideration of comments” are
normally posted as part of the Standards Drafting Process to help commenters
understand the SDT approach to comments made, and can affect subsequent
comments submitted. Peak encourages NERC to post a “consideration of
comments” from all comment periods.
In Attachment 2 under I: Design bullet 6, it states that the effects of future BES
modifications… this seems to go outside of the scope of the operating horizon on
which the RC is focused.
Document Name:
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0
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0
Kelly Dash - Kelly Dash On Behalf of: Robert Winston, Con Ed - Consolidated Edison Co. of New
York, 3, 1, 5, 6
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
In the Rationale for Requirement R1, the last sentence of the first paragraph is “A
functional modification is any modification to a RAS beyond the replacement of
components that preserves the original functionality.” How will “any modification
to a RAS beyond the replacement of components” preserve the original
functionality? The term “functional modification” requires clarification. Suggest
developing a formal definition:
RAS Functional Modification--a change to the resultant action for which a RAS is
designed.
Rationale for Requirement R8--We agree with segmented testing. However, the
requirement does not state this and implies an overall test should still be
performed.
R8 currently states:
“At least once every six‐ calendar years, each RAS‐ owner shall perform a
functional test of each RAS to verify the overall RAS performance and the proper
operation of non-Protection System components.”
Suggest revising to:
“At least once every six‐ calendar years, each RAS‐ owner shall perform a
functional test of each RAS to verify the overall RAS performance and the proper
operation of non-Protection System components. This test can be either:
An end to end test encompassing all components and testing actual
functionality
A segmented test to test all the components by grouping them together
into blocks until all parts of the RAS have been tested”
Additional information in the Technical Guideline may be required to explain how
the six year cycle is measured when allowing segmented testing. Segmented
testing can test all components of an RAS every six years, but an individual
component could end up being tested once every 10 years. For example, a RAS
is designed so that it is comprised of a segment “A” and a segment “B”. Segment
“A” is tested in year 1, segment “B” is tested in year 5. As per Requirement R8,
the RAS has been tested within “six-calendar years.” The clocks starts for the
next functional test period and segment “B” is tested in year 1 (one year since its
first test) and segment “A” tested in year 5 (nine years since its first test). The
RAS was tested within the “six-calendar years”, but segment “A” had a nine year
interval. Is this what is intended?
The RAS-owner should be included in Attachment 3.
Document Name:
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike Smith - Manitoba Hydro - 1 Selected Answer:
Answer Comment:
1.
Regarding R1, it is not clear what the term “Functionally Modified” means.
“A functional modification is any modification to a RAS beyond the replacement of
components that preserves the original functionality” does not make sense. Does
changing some overall scheme's functional logic without replacing any hardware
device qualify as “Functional Modified”?
2.
R2 should be changed to “Each Reliability Coordinator that receives
Attachment 1 information pursuant to Requirement R1, shall, within four‐ full‐
calendar months of receipt, or on a mutually agreed upon schedule, perform a
review of the RAS in accordance with Attachment 2, and provide written feedback
including any identified reliability issues to the RAS‐ entity”.
3.
R3 should be changed to “Following the review performed pursuant to
Requirement R2 and receiving the feedback from the reviewing RC, the RAS‐
entity shall address each identified issue and obtain approval from each reviewing
Reliability Coordinator prior to placing a new or functionally modified RAS in
service or retiring an existing RAS.
4.
R5 requires RAS owner to analyze the performance of every RAS
operations. It is not clear how much detail is required in this analysis. For those
RAS schemes that operates routinely and regularly as designed, is a declaration
of correct operation sufficient analysis?
5.
R6 should be changed to “Within six‐ full‐ calendar months of identifying or
being notified of a deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐ owner shall participate in developing a Corrective
Action Plan (CAP) and submit the CAP to its reviewing Reliability Coordinator(s)”.
Document Name:
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Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
Reclamation suggests that the drafting team remove Generator Owners from the
applicability section of the standard. Reclamation is unclear on how a Generator
Owner could be considered to own all or part of a RAS. Reclamation does not
believe that Generator Owners are well situated to analyze system-level RAS
impacts or be considered a RAS-entity.
Reclamation believes that a list of elements that may constitute remedial action
scheme elements would be helpful for understanding the scope of the
standard. Project 2010-05.2, Phase 2 of Protection Systems, defines RAS by
listing elements which do not individually constitute RAS. Reclamation is unclear
on whether only protection system elements are intended to be considered part of
a RAS, or whether elements affected by RAS operation like transmission lines or
generators may also be considered RAS elements. Reclamation suggests the
inclusion of a guidelines and technical basis section that better defines the
parameters of RAS that must be analyzed under R4 and R6, and their
relationship to system elements affected by RAS.
Reclamation also suggests that the RAS-entity should be responsible for the R5
analysis of each RAS operation or each failure of a RAS to operate. As written,
the requirement would impose duplicative analysis requirements upon RAS
owners that would not result in a corresponding reliability benefit. In addition,
Reclamation believes that requiring each RAS-owner to conduct an analysis of
each RAS operation is unwarranted because owners of one component of a RAS,
such as a Generator Owner, would not be in the best position to analyze the RAS
operation or its impact on the system. The RAS-entity is the RAS-owner
designated to represent all RAS-owners for coordinating the review and approval
of a RAS. As outlined in the Technical Justifications, “[t]he purpose of the RASentity is to be the single information conduit with each reviewing Reliability
Coordinator (RC) for all RAS-owners for each RAS.” Reclamation believes the
RAS analysis requirement should apply to the entity best situated to analyze the
overall RAS operation, the RAS-entity.
Finally, Reclamation suggests that the RAS-entity should be responsible for the
R8 functional test of each RAS that is required at least once every six calendar
years. A RAS-owner responsible for limited RAS components would not be able
to verify the overall RAS performance. The RAS-entity should be responsible for
coordinating a functional test with all RAS-owners.
Document Name:
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0
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0
David Kiguel - David Kiguel - 8 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Anthony Jablonski - ReliabilityFirst - 10 Selected Answer:
Answer Comment:
1. Applicability Section:
i.
ReliabilityFirst believes the “RAS‐ entity” functional entity under
the “Applicability” section may cause issues regarding which
entity is responsible for requirements related to the “RAS‐
entity”. Absent any requirements requiring the RAS-owners to
designate and make known the official RAS‐ entity, it may be
difficult to assess compliance on the RAS-entity. ReliabilityFirst
recommends including a new Requirement R1 as follows:
a. R1. For each RAS that is owned by multiple RASowners, the RAS-owners shall designate one RAS‐ entity
and inform the Reliability Coordinator(s) and
Transmission Planner(s) that coordinates the area(s)
where the RAS is located of such designation
2. Requirement R5
i.
As written, if there are multiple RAS-owners of a RAS, the
expectation is to have multiple analyses
performed. ReliabilityFirst believes it would be more appropriate
to require the RAS-entity to perform one analysis with
coordination of all associated RAS-owners.
3. Requirement R8
i.
Requirement R8 requires each RAS‐ owner to perform a
functional test of each RAS. As written, in the case where
multiple RAS-owners own a single RAS, multiple tests of the
same RAS would be required to be run. ReliabilityFirst believes
in cases where a RAS is owned by multiple RAS-owners, a single
test should be required by the designated RAS-entity in
conjunction with all the RAS-owners.
4. VSL for Requirement R4
i.
The time frames for the VSL for Requirement R4 are not all
inclusive. For example, the Lower VSL states “less than 61‐
fullcalendar months” while the moderate VSL states “greater than
61‐ full‐ calendar months”. In this example it is unclear which
VSL category an entity falls under if they perform the evaluation
in 61 months. Listed below is an example of the Lower VSL for
the SDT’s consideration.
a. The Transmission Planner performed the evaluation in
accordance with Requirement R4, but in greater than
60‐ full‐ calendar months but less than [or equal to] 61‐
fullcalendar months.
5. VSL for Requirement R7
i.
The Lower VSL states that if an entity failed both 7.2 and 7.3 they
would fall under the Lower category. ReliabilityFirst questions
what VSL an entity would fall under in the scenario where an
entity is compliant with 7.2 but not 7.3?
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The RAS‐ owner implemented a CAP (Part 7.1), but
failed to update the CAP (Part 7.2) if actions or
timetables changed [OR] failed to notify one or more of
the reviewing Reliability Coordinator(s) (Part 7.3), in
accordance with Requirement R7.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Answer Comment:
Requirement R5: The SRC agrees that the RAS entity should evaluate RASs
under the circumstances identified in Requirement R5, but would suggest that
such entities be required to provide the results of such assessments to their
Reliability Coordinator and Planning Coordinator.
Requirement R9: In conjunction with the comment provided under Q2 to replace
the TP with the PC, while the SRC agrees that the RC is the appropriate entity to
maintain the database, it suggests that the Reliability Coordinator be required to
share its database with the applicable Planning Coordinator(s) as some entities
may have a need for planned RAS information for modeling and to ensure that
appropriate information is shared across the long- and short-term horizons.
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Electric Reliability Council of Texas, Inc., 2, Axson Elizabeth
Oliver Burke - Entergy - Entergy Services, Inc. - 1 Selected Answer:
Answer Comment:
Entergy supports the SERC PCS comments on this standard.
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Mark Kenny - Eversource Energy - 3 Selected Answer:
Answer Comment:
Regarding the Applicability Section 4.1.4 for the RAS-entity, who designates the
RAS-owner to represent all RAS-owner(s)?
In the Rationale for Requirement R1, last sentence of the first paragraph, “A
functional modification is any modification to a RAS beyond the replacement of
components that preserves the original functionality.” How will “any modification
to a RAS beyond the replacement of components” preserve the original
functionality? Functional modification requires clarification. Suggest developing
a formal definition:
RAS Functional Modification--a change to the resultant action for which a RAS is
designed.
Rationale for Requirement R8--We agree with segmented testing. However, the
requirement does not state this and implies an overall test should still be
performed.
R8 currently states:At least once every six‐ calendar years, each RAS‐ owner
shall perform a functional test of each RAS to verify the overall RAS performance
and the proper operation of non-Protection System components.
Suggest revising to: At least once every six‐ calendar years, each RAS‐ owner
shall perform a functional test of each RAS to verify the overall RAS performance
and the proper operation of non-Protection System components. This test can be
either:
o An end to end test encompassing all components and testing actual
functionality
o A segmented test to test all the components by grouping them together into
blocks until all parts of the RAS have been tested
Additional information in the Technical Guideline may be required to explain how
the six year cycle is measured when allowing segmented testing. Segmented
testing can test all components of an RAS every six years, but an individual
component could end up being tested once every 10 years. For example, a RAS
is designed so that it is comprised of a segment “A”, and a segment
“B”. Segment “A” is tested in year 1, segment “B” is tested in year 5. As per
Requirement R8 the RAS has been tested within “six-calendar years.” The clocks
starts for the next functional test period, and segment “B” is tested in year 1 (one
year since its first test), and segment “B” tested in year 5 (nine years since its first
test). The RAS was tested within the “six-calendar years”, but segment “B” had a
nine year interval. Is this what is intended?
The RAS-owner should be included in Attachment 3.
R8 and guidance provided in the supplemental material as written appears to
overstep the direction provided by the SAR which states that the standard will
address maintenance and testing on non-Protection System components of a
RAS. Maintenance of Protection Systems installed as a RAS for BES reliability is
clearly covered in PRC-005. NPCC is very concerned that there are different
timeframes and duplicative testing for RAS components. In particular, the
supplemental material provided is very confusing and appears to suggest
duplicative testing compared to testing already required in PRC-005. NPCC
suggests that all testing requirements for RAS should be contained in one
standard.
NPCC suggests deletion of the phase “including any identified deficiencies” in R5
because requirements R5.1 through R5.4 clearly define the necessary level of
analysis required by the RAS-owner. Leaving this phrase in will lead to confusion
over whether the proper operation of a “composite” RAS is considered a
deficiency if one of the two redundant RAS suffer a component failure.
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Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
Attachment 1, Section III-Implementation states, “5. Documentation describing
the functional testing process.” Dominion recommends deleting this bullet. This
information is not necessarily available during the preliminary design phase. The
approval of the design is sought prior to detailed engineering. (Planning)
In R5 it states that the RAS owner analyzes the event, but in flow chart it states
RAS owner and TP. Dominion suggests that the content in the Flow Chart be
consistent with language of the Requirement.
R5 references the timeframe “within 120 calendar days”, however in other areas
of the document the time frame is stated to be “within XX calendar
months”. Dominion suggests updating the document to reflect the actual
timeframe. Dominion also believes consistency is needed and suggests the
timeframes reflect "full calendar months” versus “months”.
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John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Answer Comment:
1. In addition to RAS-entity’s, RAS-owners also have compliance
obligations. Yet RAS-owners are not identified in any of the attachments.
In addition, the RAS-related equipment of each owner should be
identified in one attachment for use by the Reliability Coordinator, the
Transmission Planner, and the Compliance Enforcement
Authority. Expanding Attachment 3 may be the most efficient way to
address these concerns.
2. R5 should be modified by changing this phrase: “…analyze the RAS
performance…” to “analyze the performance of its RAS-related
equipment.” In cases where there are multiple RAS owners, a single
RAS-owner cannot analyze the performance of the entire RAS; it can
only analyze the performance of its own RAS-related equipment.
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PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
Group Information
Group Name:
FE RBB
Group Member Name Entity
Region
Segments
William Smith
FirstenergyCorp
RFC
1
Cindy Stewart
FirstEnergy Corp.
RFC
3
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA - Not
Applicable
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Voter Information
Voter
Segment
Richard Hoag
1,3,4,5,6
Entity
Region(s)
FirstEnergy - FirstEnergy Corporation
RFC
Selected Answer:
Answer Comment:
FirstEnergy would like additional clarification on the phrase “RAS controller” in the
second paragraph of the Supplemental Material section in “Applicability”, 4.1.4
RAS-entity.
Additionally, FirstEnergy seeks to confirm that if a RAS system operates as
planned/designed durnng normal operations then can the data from this actual
operation be used to verify/satisfy testing requirements?
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Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-05.3 Submitted 10-5-15
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Brian O'Boyle
Consolidated Edison Co. of New
York, Inc.
NPCC
8
Peter Yost
Consolidated Edison Co. of New
York, Inc.
NPCC
3
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
Si Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
Because feeder loading can be changed intentionally, it is frequent to add,
substitute, or remove load tripping devices (not distributed relays) in order to
maintain the amount of load that is required by a load tripping RAS. Would these
changes constitute a RAS functional modification? If so, suggest revising the
definition of RAS functional modification. The Attachment 1 procedure that would
have to be applied would be overly burdensome.
Regarding the Applicability Section 4.1.4 for the RAS-entity, who designates the
RAS-owner to represent all RAS-owner(s)?
In the Rationale for Requirement R1, last sentence of the first paragraph, “A
functional modification is any modification to a RAS beyond the replacement of
components that preserves the original functionality.” How will “any modification
to a RAS beyond the replacement of components” preserve the original
functionality? Functional modification requires clarification. Suggest developing
a formal definition:
RAS Functional Modification--a change to the resultant action for which a RAS is
designed.
Rationale for Requirement R8--We agree with segmented testing. However, the
requirement does not state this and implies an overall test should still be
performed.
R8 currently states:
At least once every six‐ calendar years, each RAS‐ owner shall perform a
functional test of each RAS to verify the overall RAS performance and the proper
operation of non-Protection System components.
Suggest revising to:
At least once every six‐ calendar years, each RAS‐ owner shall perform a
functional test of each RAS to verify the overall RAS performance and the proper
operation of non-Protection System components. This test can be either:
o An end-to-end test encompassing all components and testing actual
functionality
o A segmented test to test all the components by grouping them together
into blocks until all parts of the RAS have been tested
Additional information in the Technical Guideline may be required to explain how
the six year cycle is measured when allowing segmented testing. Segmented
testing can test all components of an RAS every six years, but an individual
component could end up being tested once every 10 years. For example, a RAS
is designed so that it is comprised of a segment “A”, and a segment
“B”. Segment “A” is tested in year 1, segment “B” is tested in year 5. As per
Requirement R8 the RAS has been tested within “six-calendar years.” The clock
starts for the next functional test period, and segment “B” is tested in year 1 (one
year since its first test), and segment “A” tested in year 5 (nine years since its first
test). The RAS was tested within the “six-calendar years”, but segment “A” had a
nine year interval. Is this what is intended? It should be required that all
segments be tested in the same calendar year.
The RAS-owner should be included in Attachment 3.
Requirement R8 and guidance provided in the supplemental material as written
go beyond the direction stipulated by the SAR which states that the standard will
address maintenance and testing on non-Protection System components of a
RAS. Maintenance of Protection Systems installed as a RAS for BES reliability is
clearly covered in PRC-005. We are very concerned that there are different
timeframes and duplicative testing for RAS components. In particular, the
supplemental material provided is very confusing and appears to suggest
duplicative testing compared to testing already required by PRC-005. Suggest
that all testing requirements for RAS should be contained in one standard. The
testing time periods should be made consistent with Table 1-1 in PRC-005,
specifically 6 years for an unmonitored protection system, and 12 years for an
unmonitored microprocessor protection system.
NPCC suggests deletion of the phase “including any identified deficiencies” in R5
because Parts 5.1 through 5.4 clearly define the necessary level of analysis
required by the RAS-owner. Leaving this phrase in will lead to confusion over
whether the proper operation of a “composite” RAS is considered a deficiency if
one of the two redundant RAS suffer a component failure.
In C. Compliance, Section 1.2 Evidence Retention: the RC and TP have not been
included. The TO, GO and DP are requested to keep data for requirements that
they might not be responsible for.
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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Answer Comment:
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Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6 Selected Answer:
Answer Comment:
Tacoma Power recommends that the definition of ‘RAS-owner’ be limited to
functional ownership, as opposed to component ownership. For example, if one
company owns a station DC supply, some wiring, and trip coil, but another
company owns the control device at the same location, the entity that owns the
control device should be a RAS-owner, and the entity that owns the station DC
supply, wiring, and trip coil should not be a RAS-owner. Another example would
be an entity that owns sensing devices that another entity uses to provide inputs
to a relay or PLC that it owns; the entity that owns the sensing devices in this
example should not be a RAS-owner. Yet another example is when one entity
owns a portion of the communications system; simply owning part of the
communications system should not make the entity a RAS-owner.
In the Q & A document, section 9, top of page 6, what if timing is only critical on
the order of minutes (e.g., remediation of thermal overload). Could replacement
of a T1 multiplexor possibly not be considered a RAS functional change in this
case?
In the Q & A document, section 9, page 6, the example of “replacement of a failed
RAS component with an identical component” seems overly exclusive. It is
recommended to replace “identical” with “substantially identical.”
In Requirement R6, why is “six-full calendar months,” instead of simply “six
calendar months,” used?
In the Supplemental Material section, page 27, the following sentence has a
grammatical/mechanical issue: “A RAS is only allowed to drop non‐
consequential load or interrupt Firm Transmission Service can do that only if that
action is allowed for the Contingency for which it is designed.”
In the Supplemental Material section, page 28, the following passage does not
seem to read well: “These changes could result in inadvertent activation of that
output, therefore, tripping too much load and result in violations of Facility
Ratings. Alternatively, the RAS might be designed to trip more load than
necessary (i.e., “over trip”) in order to satisfy single‐ component‐ failure
requirements. System changes could result in too little load being tripped at
affected locations and result in unacceptable BES performance if one of the loads
failed to trip.” Should the middle sentence be removed? It seems incongruous
with the other two sentences.
In the Supplemental Material section, page 29, would a CAP be required if
equipment fails that is readily replaceable/repairable? Tacoma Power maintains
that CAP’s should be required for issues that will require a longer time to
address. In general, notification of RAS equipment failures is addressed by other
standards.
In the Supplemental Material section, page 30, change “the , the” to “then, the.”
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Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Answer Comment:
Although neither the Applicability section nor the Requirements of this draft
standard distinguish between Protection System components and non-Protection
System components of a RAS, the associated supporting information does make
such a distinction. For example, the first paragraph of the Background
Information section on the Unofficial Comment Form includes the following:
“The maintenance of the Protection System components associated with RAS
(PRC-017-1 Remedial Action Scheme Maintenance and Testing) are already
addressed in PRC-005. PRC-012-2 addresses the testing of the non-Protection
System components associated with RAS/SPS.”
NERC’s supporting information elsewhere suggests that examples of nonProtection System components include programmable logic controllers,
computers, and the control functions of microprocessor relays.
Based on TANC’s understanding of NERC’s intent for this standard, we suggest
that NERC modify the definition of RAS-owner that is provided in the standard’s
Applicability section to the following.
“RAS-owner - the Transmission Owner, Generator Owner, or Distribution Provider
owns all or part of the non-Protection System components of a RAS” (bold
text is added to current proposed definition).
TANC’s proposed modified definition would clarify that this standard and its
requirements are not applicable to a Transmission Owner, Generator Owner, or
Distribution Provider that doesn’t own any non-Protection System components of
a RAS.
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Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Answer Comment:
Requirement R9: In conjunction with our comment under Q2 to replace TP
with PC, while we agree that the RC is the appropriate entity to maintain the
database, we suggest adding the Planning Coordinator to this requirement
for RASs that have been planned and evaluated in the long-term planning
timeframe. Some entities may have a need for planned RAS information for
modeling.
We recommend that the standard should recognize that all RAS are not equal
and therefore should not need the same level of design review (as per R1),
performance requirement in case of RAS failure (as per 4.4), and operation
analysis (as per R5). We suggest defining two or more “class” or “type” for RAS
based on the impact of their misoperation or failure to operate on the system
performance. Different class or type of RAS will then have different levels of
design, performance and analysis requirements.
R8 and guidance provided in the supplemental material as written appears to
overstep the direction provided by the SAR which states that the standard will
address maintenance and testing on non-Protection System components of a
RAS. Maintenance of Protection Systems installed as a RAS for BES reliability is
clearly covered in PRC-005. The IESO is very concerned that there are different
timeframes and duplicative testing for RAS components. In particular, the
supplemental material provided is very confusing and appears to suggest
duplicative testing compared to testing already required in PRC-005. The IESO
suggests that all testing requirements for RAS should be contained in one
standard. NERC PRC-005 applies to Protection Systems installed as Remedial
Action Schemes for BES reliability. As such, all RAS Protective Relays,
Communication Systems, Voltage and Current Sensing Devices Providing Inputs
to Protective Relays, Control Circuitry, DC Supply, alarms and Automatic
Reclosing Components are already included in PRC-005. Lastly, this
requirement would force entities to perform testing on local area schemes; yet
non-BES components are not subject to maintenance requirements under NERC
PRC-005. Typing would be a good mythology to distinguish which RAS schemes
should be subject to the strict maintenance requirements.
The IESO suggests deletion of the phase “including any identified deficiencies” in
R5 because requirements R5.1 through R5.4 clearly define the necessary level of
analysis required by the RAS-owner. Leaving this phrase in will lead to confusion
over whether the proper operation of a “composite” RAS is considered a
deficiency if one of the two redundant RAS suffer a component failure.
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Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
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Jamison Cawley - Nebraska Public Power District - 1 Selected Answer:
Answer Comment:
The second version of PRC-005 was intended to include all testing and
maintenance requirements from PRC-017, and facilitate the retirement of PRC017. Requirement 8 of the current draft of this standard (PRC-012-2) includes
testing and maintenance requirements related to those found in PRC-017-0.
Additionally, Requirement 8 of PRC-012-2 expands on those found in PRC-017-0
by including non-Protection System components. We feel this requirement should
not be included in PRC-012-2, and we request a clear description of the
differences of the intended purpose of the proposed PRC-012-2 Requirement 8
and that of PRC-017-0/PRC-005-2. Furthermore, the remaining requirements of
PRC-012-2 seem to be primarily focused on system planning, and consideration
should be given to moving these to the TPL standard family.
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Nebraska Public Power District, 3, Eddleman Tony
Andrew Gallo - Austin Energy - 6 Selected Answer:
Answer Comment:
City of Austin dba Austin Energy suggests the SDT add clarifying language to R8
to account for a RAS-owner who owns only part of a RAS. In doing so, the SDT
may need to consider how a partial RAS-owner will be able “to verify the overall
RAS performance.”
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Dixie Wells - Lower Colorado River Authority - 5 Group Information
Group Name:
LCRA Compliance
Group Member Name Entity
Region
Segments
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Voter Information
Voter
Segment
Dixie Wells
5
Entity
Region(s)
Lower Colorado River Authority
Selected Answer:
Answer Comment:
To address existing entity NERC registration in the ERCOT region, “Transmission
Planner” should be replaced with “Transmission Planner (in the ERCOT Region
this applies to the Planning Authority and /or Reliability Coordinator.)”
R4. Each Transmission Planner (in the ERCOT Region this applies to the
Planning Authority and /or Reliability Coordinator) shall perform an evaluation of
each RAS within its planning area at least once every 60‐ full‐ calendar‐ months
and provide the RAS‐ owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each evaluation shall determine
whether: [Violation Risk Factor: Medium] [Time Horizon: Long‐ term Planning]
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Voter Information
Voter
Segment
Shannon Mickens
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
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Tony Eddleman - Nebraska Public Power District - 3 Selected Answer:
Answer Comment:
The second version of PRC-005 was intended to include all testing and
maintenance requirements from PRC-017, and facilitate the retirement of PRC017. Requirement 8 of the current draft of this standard (PRC-012-2) includes
testing and maintenance requirements related to those found in PRC-017-0.
Additionally, Requirement 8 of PRC-012-2 expands on those found in PRC-017-0
by including non-Protection System components. We feel this requirement should
not be included in PRC-012-2, and we request a clear description of the
differences of the intended purpose of the proposed PRC-012-2 Requirement 8
and that of PRC-017-0/PRC-005-2. Furthermore, the remaining requirements of
PRC-012-2 seem to be primarily focused on system planning, and consideration
should be given to moving these to the TPL standard family.
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Nebraska Public Power District, 1, Cawley Jamison
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Answer Comment:
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Don Schmit - Nebraska Public Power District - 5 Selected Answer:
Answer Comment:
The second version of PRC-005 was intended to include all testing and
maintenance requirements from PRC-017, and facilitate the retirement of PRC017. Requirement 8 of the current draft of this standard (PRC-012-2) includes
testing and maintenance requirements related to those found in PRC-017-0.
Additionally, Requirement 8 of PRC-012-2 expands on those found in PRC-017-0
by including non-Protection System components. We feel this requirement should
not be included in PRC-012-2, and we request a clear description of the
differences of the intended purpose of the proposed PRC-012-2 Requirement 8
and that of PRC-017-0/PRC-005-2. Furthermore, the remaining requirements of
PRC-012-2 seem to be primarily focused on system planning, and consideration
should be given to moving these to the TPL standard family.
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Nebraska Public Power District, 1, Cawley Jamison
Jeff Wells - Grand River Dam Authority - 3 Selected Answer:
Answer Comment:
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
Texas RE seeks clarification on the following:
If a RAS is implemented to run-back a generator due to a line loading
trigger level, is the Generator Owner a RAS-owner by default? Or is it
dependent upon the ownership of the components that are used (e.g.,
protective or auxiliary relays, communication systems, sensing devices,
station DC, control circuitry, etc.)?
In Requirement R5, is the responsibility associated with the each RASowner correct? Should that responsibility be the RAS-entity (in
collaboration with all RAS-owners) to avoid multiple analysis activities
which may result in conflicting results and/or CAPs? If one RAS-owner
finds a deficiency in another owner’s portion of the RAS, how is that
notification made?
In Requirement R5 there is no notification of a deficiency to a RASowner. Is notification considered to be when a RAS-owner recognizes a
deficiency in its part of the RAS? R6 references a notification but it is not
clear in R5.
Does the SDT consider “arming”, whether it signals another party to act
or is used in situational awareness, as an integral part of RAS
operation? Some RAS designs include an “arming” phase (e.g., A RAS
will “arm” if the amperage on line X measure 900 amps. If the amperage
measures 920 amps the RAS will activate. In some designs, “arming”
may signal action to be taken by another party is needed (e.g. generator
runback to level X), and if the action is not taken the RAS may fully
activate (e.g. trip generator).) In the Supplemental Material (and
somewhat, but not totally, mirrored in the rationale for R5) there is the
statement: “A RAS operational performance analysis is intended to: (1)
verify RAS operation is consistent with implemented design; or (2) identify
RAS performance deficiency(ies) that manifested in the incorrect RAS
operation or failure of RAS to operate when expected.” Failure of a RAS
to arm, if designed to arm, is indicative that the design was improperly
implemented.
In Requirement R8, which entity responsible for coordinating the
functional test for a multi-owner RAS that covers a wide area? The
segmented approach referred to in the rationale may cover an individual
RAS-owner’s trip function or communications, but there needs to be an
overall functional test of the logic that arms/disarms/activates the RAS,
which may involve multiple RAS-owners. Texas RE recommends
changing the requirement language to “RAS-owner, or RAS-entity as
mutually agreed by the RAS-owners shall…”. Also, a functional test
should be required if there is a system change that affects one or more
Elements that are monitored or operated as part of a RAS, in order to
verify any logic changes. Requirements R1-R3 currently do not address
functional testing, only the design. Texas RE recommends R8 indicate
“proper operation of RAS” elements and not limit the functional test
verification to non-Protection System components. Some Protection
System components involved in the proper operation of a RAS may have
an extended maintenance intervals and the RAS would not be
functionally tested without including Protection System
components. Overall RAS performance cannot be attained without
functionally testing all aspects of the RAS.
Texas RE noticed an inconsistency between the requirement language and the
RSAW. The requirement language of Requirement R5 states “Each RAS-owner
shall” but the Note to Auditor in the Requirement R5 section of the RSAW
indicates that a RAS-entity can provide the analysis. Registered entities are held
accountable to the language of the requirement. Introducing the concept of a
RAS-entity providing the information adds confusion. If the intent is for both the
RAS-Owner and the RAS-entity to be able to analyze RAS performance and
provide the results, Texas RE recommends changing the requirement language
to “RAS-owner, or RAS-entity as mutually agreed by the RAS-owners
analyze…”. Texas RE supports the idea of a RAS-entity doing the analysis.
Additionally, Texas RE recommends a requirement to report the degraded RAS to
the RC. Texas RE noticed the referenced Standards/Requirements (i.e.,
Supplemental Material indicates PRC-001 R6 and TOP-001-2 R5) are either
being retired or are not explicit enough to ensure that the reliability of the system
is maintained for those who should have situational awareness. This is a
perceived gap due to the current steady state of the standards.
Texas RE recommends Attachment 3 include the RAS-owner(s) as well as the
RAS-entity. If Requirement R9 is left as “at a minimum”, that is all that will be
done. Ownership is critical to know because of the responsibilities required in the
majority of the Requirements (e.g., How will the TP provide results to owners
without knowing all the owners?) The TP does not, generally, know the RASowners based on the ownership at the component level.
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Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
Answer Comment:
·
Hydro One Networks Inc. recommends that the standard should recognize
that all RASs are not equal and therefore, should not be subject to the same level
of design review (as per R1), performance requirements in case of RAS failure
(as per 4.4), and operation analysis (as per R5). We suggest defining two or
more “class” or “type” for RAS based on the impact of their misoperation or failure
to operate on the system performance. Different classes or types of RAS will
consequently have different levels of design, performance and analysis
requirements associated with them. Hydro One Networks Inc. would like to
emphasize that in the absence of a means of differentiation (via typing or classes
of RAS), utilities will feel compelled to spend significant capital, for little or no
material improvement to system reliability.
·
Hydro One Networks Inc. believes that requirement R8 and guidance
provided in the supplemental material appear to overstep the direction provided
by the SAR, which states that the standard will address maintenance and testing
on non-Protection System components of a RAS. Maintenance of Protection
Systems installed as a RAS for BES reliability is clearly covered in PRC005. Hydro One Networks Inc. further joins the NPCC with its concern over the
different timeframes provided and duplicative testing for RAS components. In
particular, the supplemental material provided is very confusing and appears to
suggest duplicative testing compared to testing already required in PRC-
005. Hydro One Networks Inc. agrees with the NPCC and suggests that all
testing requirements for RAS should be contained in one standard. NERC PRC005 applies to Protection Systems installed as Remedial Action Schemes for BES
reliability. As such, all RAS Protective Relays, Communication Systems, Voltage
and Current Sensing Devices Providing Inputs to Protective Relays, Control
Circuitry, DC Supply, alarms and Automatic Reclosing Components are already
included in PRC-005. Lastly, this requirement would force entities to perform
testing on local area schemes; yet non-BES components are not subject to
maintenance requirements under NERC PRC-005. Typing would be a good
mythology to distinguish which RAS schemes should be subject to the strict
maintenance requirements.
·
Hydro One Networks Inc. also agrees with the NPCC in suggesting the
deletion of the phase “including any identified deficiencies” in R5 because
requirements R5.1 through R5.4 clearly define the necessary level of analysis
required by the RAS-owner. Leaving this phrase in would lead to confusion over
whether the proper operation of a “composite” RAS is considered a deficiency if
one of the two redundant RAS suffer a component failure.
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Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
The roles and relationships between the RAS-entity and the RAS-owners could
be made clearer throughout the standard. Overall, FMPA supports the drafting
team’s approach, but there have been several comments submitted that should
be considered before the standard is approved and would like to see outreach
done before the next posting of the standard for comment and ballot.
Document Name:
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0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
(1) Requirement R9 requires the RC to update its RAS database
annually. However, we believe the requirement should be rewritten to require the
RC to develop and implement a process to conduct a review of its database and
at what frequency. If a RAS-owner has not made any changes to functionality
and system conditions and operating configurations are as expected, we feel this
requirement is more of an administrative burden falling under Paragraph 81 Data
Collection criteria.
(2) We question how a RC is expected to maintain a dated revision history as
evidence for Requirement R9 when the context of this requirement is to update a
database. We believe the requirement is more of an administrative burden falling
under Paragraph 81 Data Collection criteria, and the requirement should be
rewritten to require the RC to develop and implement a process to conduct a
review of its database and at what frequency.
(3) We believe the evidence retention of this standard should identify retention
periods for applicable entities and not limit retention just for TOs, GOs, and DPs.
(4) The VSLs for Requirements R1 and R3 currently have only a Severe VSL
identified. We believe the VSL criteria for these requirements could be written on
a sliding time scale based on the projected installation or retirement dates of a
RAS.
(5) We believe the VSL criteria listed with many requirements is too
condensed. We recommend incrementing the criteria for Requirement R4 by
quarters instead of by months. Moreover, we recommend incrementing the
criteria for Requirement R5 by months rather than by every ten days. We also
recommend incrementing the criteria for Requirements R8 and R9 by quarters
rather every thirty days.
(6) We have concerns that the SDT has introduced a new measure of time, the
“full-calendar-month.” This measure will cause confusion with implementation
and during audits. Moreover, there is inconsistent uses of this time measure
within the standard. The SDT uses 60-full-calendar-months in R4, but does not
use the same measurement in R5 for 120-calendar days and R8 for six-calendar
years. Should R5 be four-full-calendar-months and R8 be six-full-calendaryears? The rationale for “full-calendar months” is only specified within the RSAW
of this Standard. We feel the SDT should remove the measure of “full-calendar
months” and replace it with “calendar months” to be consistent with the other
NERC standards.
(7) We thank you for this opportunity to comment on this standard.
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
BPA believes R5’s reporting to the RC of the correct operation of a RAS is unduly
onerous without providing value. BPA analyzes all RAS operations. If we see a
scheme that operates too frequently (this is very subjective), we evaluate that
scheme to see if there is something that can be done to minimize the number of
operations. BPA proposes this be deleted from the requirement.
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Consideration of Comments
Project Name: 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes | PRC‐012‐2
Comment Period Start Date: 8/20/2015
Comment Period End Date: 10/5/2015
Associated Ballot: 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC‐012‐2 IN 1 ST
There were 60 responses, including comments from approximately 155 different people from approximately 104 different
companies representing 9 of the 10 Industry Segments as shown on the following pages.
All comments submitted can be reviewed in their original format on the project page.
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 Director of Standards, Howard
Gugel (via email) or at (404) 446‐9693.
The drafting team made the following changes to the draft standard and implementation plan based on stakeholder comments:
Reliability Standard PRC-012-2
Applicability
Replaced the Transmission Planner with the Planning Coordinator.
Consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the Transmission Owner, Generator
Owner, or Distribution Provider that owns a RAS.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
1
Requirements
Requirement R1
Made minor clarifying changes.
Requirement R2
Made a minor clarifying change.
Requirement R3
Restructured for clarity.
Requirement R4
Restructured for clarity and included the RAS‐entity as well as each impacted Transmission Planner and Planning Coordinator to Part
4.2 to receive the results of the RAS evaluation.
Included a provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations. Inserted a footnote for additional explanation.
Requirement R5
Restructured for clarity and added “on a mutually agreed upon schedule” to allow longer periods for the RAS operational analysis to
be performed. Also changed from “analyze” to “participate in analyzing” for consistency with other requirements.
Requirement R6
Revised to include “Identifying a deficiency in its RAS pursuant to Requirement R8” as an additional trigger for the development of a CAP.
Requirement R7
Revised for clarity and added “and when the CAP is completed” to Part 7.3 regarding notification of the RC.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
2
Requirement R8
Revised to provide a twelve full calendar year test interval for all RAS designated as limited impact. Also changed from “perform” to
“participate in performing” for consistency with other requirements.
Requirement R9
Revised time period from “once each calendar year” to “once every twelve full calendar months”.
Measures, VSLs, and Attachments
Revised to be consistent with and complement the revised requirements.
Rationale Boxes and Supplemental Material
Revised to complement the revised requirements and provide additional examples and insight.
Implementation Plan
Requested Retirements
Removed references to Version 0 standards.
Applicable Entities
Replaced the Transmission Planner with the Planning Coordinator.
Consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the Transmission Owner, Generator
Owner, or Distribution Provider that owns a RAS.
Background and General Considerations
Revised to reflect issuance of FERC Order No. 818 approving the RAS standards and definition of “Remedial Action Scheme.”
Effective Date
Changed the implementation period of the standard from twelve (12) months to thirty‐six (36) months to provide entities more time
to establish the new working frameworks among RAS‐entities, Reliability Coordinators, and Planning Coordinators.
Added clarifying language for the initial performance of obligations under Requirements R4, R8, and R9.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
3
Questions
Requirements R1, R2, and R3 pertain to the submittal of Attachment 1 information to the Reliability Coordinator (RC) for the
review of a RAS, the RC using Attachment 2 as a guide for performing the RAS review, and the RC approving the RAS prior to the
RAS being placed in service. Question 1 is relevant to these activities.
1. RAS review and approval: Do you agree with the RAS review process outlined by Requirements R1, R2, and R3? If no, please
provide the basis for your disagreement and an alternate proposal.
Requirement R4 mandates that the Transmission Planner perform a technical evaluation (planning analyses) of each RAS at least
once every 60 full calendar months to verify the continued effectiveness and coordination of the RAS, including BES performance
following an inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
2. RAS Periodic Evaluations: Do you agree with the RAS planning evaluation process outlined by Requirement R4? If no, please
provide the basis for your disagreement and an alternate proposal.
3. RAS Inadvertent Operation: Do you agree with Requirement 4 Part 4.3 and Attachment 1 which stipulates that RAS inadvertent
operation due to a single component malfunction still satisfies the System performance requirements common to TPL‐001‐4 P1‐
P7 events listed in Parts 4.3.1‐4.3.5? (Note that this requirement remains the same as PRC‐012‐0 R1.4 except for the allowance
for designed‐in security that would prevent RAS inadvertent operation for any single component malfunction). If no, please
provide the basis for your disagreement and an alternate proposal.
4. RAS Single Component Failure: Do you agree with Requirement 4 Part 4.4 and Attachment 1 which stipulates that any RAS
intended to satisfy System performance requirements in a TPL standard must still satisfy those requirements when experiencing a
single component failure? (Note that this requirement remains unchanged from PRC‐012‐0 R1.3.) If no, please provide the basis
for your disagreement and an alternate proposal.
Requirements R6 and R7 pertain to the development and implementation of Corrective Action Plans (CAPs). Question 5 addresses
these requirements.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
4
5. Corrective Action Plans: Do you agree that the application of Requirements R6 and R7 would address the reliability objectives
associated with CAPs? If no, please provide the basis for your disagreement and an alternate proposal.
6. Implementation Plan: Do you agree with the Implementation Plan? If no, please provide the basis for your disagreement and
an alternate proposal.
7. If you have any other comments that you haven’t already provided in response to the above questions, please provide them
here.
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
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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5
Requirements R1, R2, and R3 pertain to the submittal of Attachment 1 information to the Reliability Coordinator (RC) for the review of a
RAS, the RC using Attachment 2 as a guide for performing the RAS review, and the RC approving the RAS prior to the RAS being placed in
service. Question 1 is relevant to these activities.
1. RAS review and approval: Do you agree with the RAS review process outlined by Requirements R1, R2, and R3? If no, please provide
the basis for your disagreement and an alternate proposal.
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Selected Answer:
Yes
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Region Segments
Joe Depoorter
Madison Gas & Electric
MRO 3,4,5,6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Barbara Kedrowski ‐ WEC Energy Group, Inc. ‐ 3,4,5,6 ‐ RFC
Selected Answer:
Yes
6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company
MRO
1
Chuck Wicklund
Otter Tail Power Company
MRO
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc
MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative
MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power Administration MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
MRO
Selected Answer:
No
1,3,5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
7
The NSRF propose revising R2 to explicitly include the engagement of any
applicable Planning Coordinators with wording like, “Each Reliability
Coordinator . . . shall in conjunction with impacted Transmission Planners and
Planning Coordinators . . .” The inclusion of Transmission Planners and
Planning Coordinators is appropriate because RASs are ‘standing, automatic’
schemes that are evaluated primarily in the planning horizon and by
Transmission Planners. In general, Reliability Coordinators do not have
planning horizon analysis information or expertise.
We further recommend that M2 and M3 be modified such that acceptable
evidence can be a Reliability Coordinator sponsored peer review by impacted
entities.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
Answer Comment:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
8
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Acceptable evidence for Measure M2 is dated reports, checklists, or other documentation detailing the RAS review was
performed, the aspect of “who” performed the review is not a factor. The drafting team declines to make the suggested
change.
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Oncor Electric Delivery believes that it is a good idea to have an independent
party review any RAS. However, 90 days for the review seems more
reasonable since they are just reviewing the scheme.
Additionally Oncor Electric Delivery believes the RAS information required in
attachment 1 contains more than is necessary for a review and cannot always
be obtained for every RAS. In fact, unless the RAS is an existing system during
the review period there are usually no schematics to review so we do not
believe it is appropriate to request schematic diagrams. The second bullet
under General section I asks for “functionality of a new RAS”, which would be
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
9
a relay functional diagram that depicts how the scheme works and that would
be available during the review process.
Response: Thank you for your comments.
The time frame of four full calendar months is consistent with current utility and regional practices. The drafting team wrote
the requirement to allow for time intervals longer or shorter than four full calendar months by including the phrase
"mutually agreed upon schedule" among the affected parties. The drafting team declines to make the suggested change.
Attachment 1 lists information that is suppled to sufficiently define the electrical and physical location of a RAS. Schematic
diagrams are listed as one example of information that may be useful but are not required. The reviewing RC will decide if
any additional information is necessary beyond what the RAS‐entity originally supplied on a case‐by‐case basis. The drafting
team modeled the RAS information required in Attachment 1 after the current WECC and NPCC (WECC and NPCC combined
represent approximately two‐thirds of existing RAS in North America) design guides and review procedures documents which
include details of the RAS design expectations and reviews. The drafting team maintains the level of detail specified in
Attachment 1 is consistent with these common practices and declines to make the suggested change.
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC
Group Name:
Seattle City Light Ballot Body
Group Member Name
Entity
Region
Pawel Krupa
Seattle City Light
WECC
Dana Wheelock
Seattle City Light
WECC
Segments
1
3
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
10
Hao Li
Seattle City Light
WECC
4
Bud (Charles) Freeman
Seattle City Light
WECC
6
Mike haynes
Seattle City Light
WECC
5
Michael Watkins
Seattle City Light
WECC
1,3,4
Faz Kasraie
Seattle City Light
WECC
5
John Clark
Seattle City Light
WECC
6
Selected Answer:
Yes
Chris Scanlon ‐ Exelon ‐ 1 ‐
Group Name:
Group Member Name
Chris Scanlon
John Bee
Selected Answer:
Exelon Utilities
Entity
Region Segments
BGE, ComEd, PECO TO's
RFC
1
BGE, ComEd, PECO LSE's
RFC
3
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
11
Jeri Freimuth ‐ APS ‐ Arizona Public Service Co. ‐ 3 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Yes
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Selected Answer:
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company Holdings
Corporation, 1
Selected Answer:
Yes
12
Maryclaire Yatsko ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5,6 ‐ FRCC
Selected Answer:
No
Answer Comment:
a. R1 references “each RAS‐entity shall submit…”, but there should only be
one RAS‐entity per RAS, is this correct?
b. The supplemental material of the Standard states that the RAS owners
needs to select an RAS‐entity or else the RC will select the RAS‐entity. This
language needs to be in the Standard if it’s going to be enforceable.
c. For the designation of the RAS‐entity between different owners, will
NERC/FERC/Regions require a CFR or JRO agreement? And what happens if
one of the RAS owners is not a NERC registered entity, i.e., not a functional
entity? Please describe what evidence needs to be provided to show
designation of responsibility to the RAS‐entity.
d. Also, most, if not all, new RASs are developed, studied, and reviewed
within the long‐term Planning Horizon by PCs and
TPs. Modifications/retirements to existing RASs have the potential to be
developed in the Operating Horizon; therefore, Seminole suggests that R1 be
broken up into two requirements, one addressing modifications/retirements
which would be specific to the “Operations Planning Horizon” and the second
addressing “new” RASs specific to the “Long‐term Planning Horizon” and
applicable to PCs as well.
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13
e. Can the drafting team define all of the components of an RAS so that
“ownership” can be determined, i.e., what equipment makes up an RAS?
Response: Thank you for your comments.
a. Yes, you are correct.
b. The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS.
c. The drafting team notes that a JRO and a CFR, provided for in Sections 507 and 508 of the NERC Rules of Procedure,
respectively, are voluntary registration relationships that entities may employ to accomplish registration responsibilities.
Among other options for sharing registration responsibility, the JRO and CFR registration relationships can be
implemented on ad hoc bases depending on the entities’ unique circumstances. Per the definition, a RAS‐owner (now
RAS‐entity) will be a Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. Each
of these functional NERC registrations are defined in the NERC Rules of Procedure. As such, the drafting team does not
foresee a situation when a RAS‐entity would not be a NERC registered entity.
d. Existing regional RAS reviews do not make any distinction between RAS conceived or modified by planning or operating
groups. The drafting team does not see any reliability benefit in bifurcating the RAS review process in this manner and
declines to make the suggested change.
e. The drafting team revised Item 1 in the Implementation Section of Attachment 1 to better describe RAS components.
The RC will make the final determination regarding the RAS components during its review.
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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14
Selected Answer:
Yes
Answer Comment:
A. It is unclear why R3 is not structured consistent to R1 even though both
requirements are prerequisites for achieving the same objective of
“placing a new or functionally modified RAS in service or retiring an
existing RAS”. Suggest restructuring R3 as follows for clarity and
consistency: “Prior to placing a new or functionally modified RAS in service
or retiring an existing RAS, the RAS‐entity shall address each issue
identified by the RAS review (performed pursuant to Requirement R2) and
obtain approval of the RAS from each reviewing Reliability Coordinator.”
B. In R1, the RAS review falls within the purview of one or more RC’s
depending on “the area(s) where the RAS is located.” What attributes
define the location of a RAS? Should the RAS location comprise of only
the station(s) where its remedial action logic processing device(s) is/are
installed? Or would the RAS location also include the stations from where
the various RAS inputs are telemetered to the logic processing device?
Would it also include the station(s) at which the RAS output(s) – that is,
remedial actions – are sent? Suggest that the standard provides clear
guidance on what comprises the RAS location. Alternatively, suggest using
a different RAS characteristic in R1 to avoid subjective and inconsistent
interpretations of what comprises RAS location.
Response: Thank you for your comments.
A. The drafting team made the suggested change.
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15
B. The drafting team maintains that the RAS location may cover multiple Reliability Coordinator Area(s) that contain any aspect
of a RAS (e.g., inputs, outputs, logic, or equipment) that allows the RAS to operate as‐designed. The drafting team declines
to make the suggested change.
Molly Devine ‐ IDACORP ‐ Idaho Power Company ‐ 1 ‐
Selected Answer:
Yes
Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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16
Response: Please see the drafting team’s responses to the referenced comments.
David Greene ‐ SERC ‐ 1,10 ‐ SERC
Group Name:
Group Member Name
Steve Edwards
Joel Masters
David Greene
Jammie Lee
Greg Davis
Selected Answer:
SERC PCS
Entity
Region Segments
Dominion
SERC
1
SCE&G
SERC
1
SERC staff
SERC
10
MEAG
SERC
1
GTC
SERC
1
Yes
Bob Thomas ‐ Illinois Municipal Electric Agency ‐ 4 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
17
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Selected Answer:
No
Answer Comment:
ATC proposes revising R2 to explicitly include the engagement of any
applicable Planning Coordinators with wording like, “Each Reliability
Coordinator........ shall in conjunction with any Planning Coordinators
.......” The inclusion of Planning Coordinators is appropriate because RASs
are ‘standing, automatic’ schemes that are evaluated primarily in the
planning horizon and by Transmission Planners. In general, Reliability
Coordinators do not have planning horizon analysis information or expertise.
Response: Thank you for your comment.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
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18
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for an RAS is determined from TPL studies and
planned system performance. References to the Reliability Coordinator
should be changed to Planning Coordinator. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐time
operating reliability of the Bulk Electric System within a Reliability
Coordinator Area.” It is not responsible for the planning or installation of a
Protection System. The NERC Functional Model does not support the RC as
being the reviewer. The RC currently does not review nor have the authority
to approve any other facility or protection system installation.
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19
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
Yes
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20
Answer Comment:
To remove possible confusion, “on a mutually agreed upon schedule” should
be changed to “on a mutually agreed upon schedule between Reliability
Coordinators and RAS‐entities.”
Response: Thank you for your comment.
The drafting team maintains that the requirement is clear, the RC and the RAS‐entity are the only parties mentioned in the
requirement. The drafting team declines to make the suggested change.
Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Selected Answer:
No
Answer Comment:
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for a RAS is determined from TPL studies and
planned system performance. The standard correctly provides the RC with an
opportunity to participate in providing opinion. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐time
operating reliability of the Bulk Electric System within a Reliability
Coordinator Area.” It is not responsible for the planning or installing a
Protection System. The NERC Functional Model does not support the RC as
being the reviewer. The RC currently does not review nor have the authority
to approve any other facility or Protection System installation. Clarification of
R3 regarding approval of the RAS after all issues have been addressed should
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21
be made. The approval mentioned in R3 could be interpreted as an approval
that each identified outstanding issue was addressed and not a complete
formal approval of the RAS. If the RC is to perform the review, we suggest the
following rewording for R3:
“Following the review performed pursuant to Requirement R2, the RAS‐
entity shall address each issue identified by the Reliability Coordinators
participating in the review and obtain final approval(s) for the RAS from each
Reliability Coordinator participating in the review, prior to placing a new or
functionally modified RAS in service or retiring an existing RAS.”
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
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22
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Answer Comment:
Southern Company
Entity
Region Segments
Southern Company Services, Inc.
SERC
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation and SERC
6
Energy Marketing
No
The owner of any protection scheme should be responsible for the correct
design and implementation of the scheme – RAS or not. Just like the design
of switching to create a blackstart cranking path by a TOP in EOP‐005‐2,
Requirement 6 must be verified by that TOP, the owner of the RAS should be
held to the same expectation that the RAS is correctly designed and
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23
implemented. If the SDT still believes that some sort of review is required,
then that review should be limited in scope to reviewing the generic content
of the RAS design and not delve into the technical depth identified in some
parts of Attachment 2.
Using the criteria outline by the SDT in its recent webinar, in addition to the
independence of the reviewer and geographic span, the team also mentioned
“expertise in planning, protection, operations, equipment”. The attributes of
this expertise to the level expected do not currently exist in most RC
organizations. RC’s are primarily operating entities (and even then primarily
in real‐time) and not experts in planning (beyond the operating time frame),
protection or equipment. Transmission Owners, Transmission Operators and
Transmission Planners normally have that expertise. The FERC acknowledged
the limited RC technical expertise in evaluating details of restoration plans in
its Order 749, Paragraph 38 (“…basis on which a reliability coordinator rejects
a restoration plan will necessarily be based on generic engineering
criteria…”). The review of a RAS by an RC should not be held to a higher
expectation due to similar limited expertise with the equipment and systems
involved in a RAS.
The “flexibility” for the RC granted in the requirement to designate a third
party would seem to immediately invalidate the original assumptions that the
RC has the compelling capability to adequately perform the review while
meeting the SDT’s characteristics of the reviewing entity. To allow this, while
still requiring the RC to be responsible for the review, seems like an improper
administrative burden and a potential compliance risk that the RC may
assume because it had to find an entity more qualified than itself to perform
the review. If an RC is not qualified to review all of the items in Attachment 2
then how can it be held responsible for the results of the review?
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24
Regarding the designation of a third party reviewer, clarification needs to be
made regarding what it means to “retain the responsibility for
compliance.” Does this simply mean that the review takes place or that there
is some implied resulting responsibility for the correct design and
implementation that the RC is now accountable for.
Finally, also regarding the designation of a third party reviewer, is the term
“third party” meant to be any entity not involved in the planning or
implementation of the RAS?
The alterative to using the RC? Although there appears to be a movement to
remove the RRO as a responsible entity from all standards, those
organizations through their membership expertise and committee structures
more closely match the characteristics stated by the SDT – expertise in
planning/protection/operations/equipment, independence by virtue of the
diversity of its members, wide area perspective, and continuity. If for some
reason the SDT, believes that the RRO still should not be involved then an
alternative could be the Planning Coordinator function which should have
similar expertise to the Transmission Planners that are to specify/design a
RAS per the functional model yet would have some independence which the
SDT is looking for.
Response: Thank you for your comments.
The drafting team agrees that the owner of the RAS is responsible for the comprehensive design and detailed
implementation of its RAS; however, the drafting team believes that an additional layer of review of the RAS should be
performed. Because the RAS‐owner (now RAS‐entity) is the party that will ultimately design and implement its protection
scheme, the RAS‐entity is not an appropriate party to perform an independent review of its own system. Rather, in its
original draft, the drafting team asserted that the Reliability Coordinator (RC), an entity with a requisite level of expertise and
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25
geographically expansive visibility, should perform a review of the RAS. Further, the drafting team maintains that, because
results from previous reviews have shown that utilizing these metrics is both effective and efficient, the comprehensive RAS
review to be performed by the RC that is currently performed by the regional entities should include the level of detail
described in Attachments 1 and 2.
The drafting team is charged with assigning the requirements of the new standard to the specific users, owners, and
operators of the Bulk‐Power System while incorporating the reliability objectives of all the RAS/SPS‐related standards. In
drafting this standard, the team has worked diligently to minimize the changes that will be required from the existing
processes. The drafting team maintains that the RC may, at its discretion, request information or assistance from other
entities to perform the RAS review. This “flexibility” to request assistance from a third party allows the RC to perform a more
robust review of the RAS if that party has a particular piece of information or can provide unique assistance. The ability of
the RC to solicit assistance in performing the RAS review does not indicate that the RC is not equipped to perform the RAS
review, or that another party should be chosen to perform that review. To the contrary, this ability ensures a more effective
RAS review. The drafting team explains in the Rationale for Requirement R2 that the RC “will retain the responsibility for
compliance with this requirement” according to the standard’s explicit applicability to the RC.
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Selected Answer:
Yes
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Selected Answer:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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26
Answer Comment:
On the whole, Reclamation agrees with the RAS review process outlined in
Requirements R1–R3. However, Reclamation believes that RAS‐owners
should also be listed in Attachment 1 and Attachment 3 and should be
notified of all RAS‐entity communications with the Reliability Coordinator
(RC). Reclamation does not believe that the RAS‐entity should be able to
release technical information about a RAS‐owner’s equipment without the
knowledge of the RAS‐owner.
Response: Thank you for your comments.
The drafting team maintains that each RAS‐owner (now RAS‐entity) would participate in producing the Attachment 1 data for
a new or functionally modified RAS being submitted for review by the RAS‐entity. The consolidation of the terms RAS‐owner
and RAS‐entity effectively addresses your Attachment 3 comment.
Mike ONeil ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐
Selected Answer:
No
Answer Comment:
Florida Power & Light appreciates the efforts of the Standard drafting Team in
consolidating the existing RAS‐related Standards into one Standard (PRC‐012),
however we disagree with the assertion that the Reliability Coordinator
(RC) is the best choice to review RAS's for new or continued implementation.
The RC is responsible for the operation rather than the planning of the BES.
RAS design and approval is best performed at the planning level. The Planning
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27
Coordinator is responsible for coordinating transmission plans and protection
systems and we believe more appropriate to review, approve and maintain
the RAS database.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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28
Group Name:
Group Member Name
Charles Yeung
Ben Li
Greg Campoli
Mark Holman
Matt Goldberg
Lori Spence
Christina Bigelow
Ali Miremadi
Selected Answer:
Answer Comment:
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐
IRC Standards Review Committee
Entity
Region Segments
SPP
SPP
2
IESO
NPCC 2
NYISO
NPCC 2
PJM
RFC
2
ISONE
NPCC 2
MISO
MRO 2
ERCOT
TRE
2
CAISO
WECC 2
No
The ISO/RTO Council Standards Review Committee (“SRC”) agrees that the RC
should have to approve the use of RAS. Pursuant to the Functional Model, the
RC does not have the authority to approve relay schemes. Nonetheless, it is
important that the RC be informed of and understand how the RAS impacts
the topology of its area of authority, identify and communicate any reliability
issues to the RAS proponents, and coordinate with the RAS Entity regarding
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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29
the in‐service date and time of the RAS. We further recommend that M2 and
M3 be modified such that acceptable evidence can be a Reliability
Coordinator sponsored peer review with impacted Transmission Planners and
Planning Coordinators.
Therefore, the SRC proposes that Requirement R3 be revised to:
R3. Following the review performed pursuant to Requirement R2, the RAS‐
entity shall address each identified issue and obtain concurrence from the
Reliability Coordinator that all identified issues are resolved prior to placing a
new or functionally modified RAS in service or retiring an existing RAS.
While the SRC is not opposed to a guideline regarding the performance of
RAS evaluations, Attachment 2 is overly prescriptive and does not allow for
impacted entities to utilize their operational experience and engineering
judgment. The SRC recommends that the introductory paragraph to
Attachment 2 be revised to provide greater flexibility regarding RAS
evaluations. The following revisions are suggested:
The following checklist provides reliability related considerations for the
Reliability Coordinator to consider for inclusion in its evaluation for each new
or functionally modified2 RAS. The RC should utilize the checklist to
determine those considerations that are applicable to the RAS evaluation
being performed; however, RAS evaluations are not limited to the checklist
items and the RC may request additional information on any reliability issue
related to the RAS.
Response: Thank you for your comments.
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The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Acceptable evidence for Measure M2 is dated reports, checklists, or other documentation detailing the RAS review was
performed, the aspect of “who” performed the review is not a factor. The drafting team declines to make the suggested
change.
Please see the revision to Requirement R3 in the draft standard.
Please see the Supplemental Material section of the standard for the technical justification of Attachment 2. It reads:
Attachment 2 is a checklist provided to assist the RC in identifying reliability considerations generally relevant to aspects of
RAS design and implementation, and also for the purpose of facilitating consistent reviews continent‐wide for each RAS to be
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31
installed or functionally modified. Most of the checklist items should be applicable to most RAS. There may be checklist
items that are not applicable to a given RAS in which case they may be noted as not applicable and skipped in the RC review.
Depending on the specifics of the RAS under review, it is possible that other reliability considerations may be identified
during the review. Any other reliability considerations, along with their resolution with respect to the particular RAS under
review, should be documented along with the Attachment 2 items that were applicable to the specific RAS under review.
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Response: Please see the drafting team’s responses to the referenced comments.
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Selected Answer:
No
Answer Comment:
With regard to R1, the RAS entity is not typically qualified to provide some of
the information required in Attachment 1, such as Sections II.3, II.4, II.5, and
II.6. This information is typically developed by Planning Coordinator (PC) or
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Transmission Planner (TP). RAS owners typically only implement the RAS as
functionally required by the PC or TP. It is noted that the Planning
Coordinator is not listed as an applicable entity and should be.
The Planning Coordinator is the correct function to determine where a RAS
Scheme is required. The need for an RAS is determined from TPL studies and
planned system performance. The standard correctly provides the RC with an
opportunity to participate in providing opinion. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐time
operating reliability of the Bulk Electric System within a Reliability
Coordinator Area.” It is not responsible for the planning or installation of a
Protection System. The NERC Functional Model
does not support the RC as being the reviewer. The RC currently does not
review nor have the authority to approve any other facility or protection
system installation. Clarification of R3 regarding approval of the RAS after all
issues have been addressed should be made. The approval mentioned in R3
could be interpreted as an approval that each identified outstanding issue
was addressed not complete formal approval of the RAS. If the RC is to
perform the review, we suggest the following:
R3‐ Following the review performed pursuant to Requirement R2, the RAS‐
entity shall address each issue identified by the Reliability Coordinators
participating in the review and obtain final approval(s) for the RAS from each
Reliability Coordinator participating in the review, prior to placing a new or
functionally modified RAS in service or retiring an existing RAS.
With regard to R3, some of the identified issues would be most appropriately
addressed by the PC or TP, especially the items in Section II of Attachment
1. It is inappropriate for RAS entity to assume compliance responsibility for
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
33
addressing each identified issue. The RAS owner for the RAS issues should be
the responsible entity.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Acceptable evidence for Measure M2 is dated reports, checklists, or other documentation detailing the RAS review was
performed, the aspect of “who” performed the review is not a factor. The drafting team declines to make the suggested
change.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
34
Please see the revision to Requirement R3 in the draft standard.
Please see the Supplemental Material section of the standard for the technical justification of Attachment 2. It reads:
Attachment 2 is a checklist provided to assist the RC in identifying reliability considerations generally relevant to aspects of
RAS design and implementation, and also for the purpose of facilitating consistent reviews continent‐wide for each RAS to be
installed or functionally modified. Most of the checklist items should be applicable to most RAS. There may be checklist
items that are not applicable to a given RAS in which case they may be noted as not applicable and skipped in the RC review.
Depending on the specifics of the RAS under review, it is possible that other reliability considerations may be identified
during the review. Any other reliability considerations, along with their resolution with respect to the particular RAS under
review, should be documented along with the Attachment 2 items that were applicable to the specific RAS under review.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Region
Larry Nash
Dominion Virginia Power
SERC
Louis Slade
Dominion Resources, Inc.
SERC
Connie Lowe
Dominion Resources, Inc.
RFC
Randi Heise
Dominion Resources, Inc,
NPCC
Selected Answer:
No
Segments
1
6
3
5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
35
Answer Comment:
As Dominion stated in its previous comments, we believe that RAS should be
reviewed and approved in both the planning and operating horizons by
designated entities within whose area(s) the Facility (ies) the RAS is designed
to protect reside.
Dominion suggests the following specific changes to R1: Prior to placing a
new or functionally modified RAS in service or retiring an existing RAS, each
RAS‐entity shall submit the information identified in Attachment 1 for review
to the Reliability Coordinator(s) and Transmission Planner(s) within whose
respective area(s) the Element(s) or Facility(ies) for which the RAS is
designed to protect is (are) located..
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
36
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
Group Member Name
Joseph Smith
Jeffrey Mueller
Tim Kucey
Karla Jara
Selected Answer:
Answer Comment:
PSEG
Entity
Region Segments
Public Service Electric and Gas
RFC
1
Public Service Electric and Gas Co.
RFC
3
PSEG Fossil LLC
RFC
5
PSEG Energy Resources & Trade LLC RFC
6
No
See the comment in #7.1. In addition, the Transmission Planner should be a
required participant in developing Attachment 1 and at least be responsible
for Section II in Attachment 1. Finally, the obligation in R3 that a RAS‐entity
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
37
address issues identified pursuant to R2 is incomplete. R3 should also place
compliance obligations on the Transmission Planner and the RAS‐owners to
participate in addressing any issues under R3.
Response: Thank you for your comments.
Please see the drafting team’s responses to the referenced comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
38
Please see the revision to Requirement R3 in the draft standard.
Please see the Supplemental Material section of the standard for the technical justification of Attachment 2. It reads:
Attachment 2 is a checklist provided to assist the RC in identifying reliability considerations generally relevant to aspects of
RAS design and implementation, and also for the purpose of facilitating consistent reviews continent‐wide for each RAS to be
installed or functionally modified. Most of the checklist items should be applicable to most RAS. There may be checklist
items that are not applicable to a given RAS in which case they may be noted as not applicable and skipped in the RC review.
Depending on the specifics of the RAS under review, it is possible that other reliability considerations may be identified
during the review. Any other reliability considerations, along with their resolution with respect to the particular RAS under
review, should be documented along with the Attachment 2 items that were applicable to the specific RAS under review.
Please see the revised Applicability section of the standard for the new description of a RAS‐entity.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The RAS‐entity is the best‐
suited entity to address any identified issues per Requirement R3. The drafting team maintains that the RAS‐entity has the
“flexibility” to request information or assistance from relevant entities (third parties).
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
39
Group Name:
Group Member Name
William Smith
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Selected Answer:
FE RBB
Entity
Region Segments
FirstenergyCorp
RFC
1
FirstEnergy Corp.
RFC
3
Ohio Edison
RFC
4
FirstEnergy Solutions
RFC
5
FirstenergyCorp
RFC
NA ‐ Not
Applicable
FirstEnergy Solutions
FRCC 6
Yes
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Region
Alan Adamson
New York State Reliability Council,
NPCC
LLC
Segments
10
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
40
David Burke
Orange and Rockland Utilities Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
Northeast Power Coordinating
Council
Northeast Utilities
NPCC
2
NPCC
10
NPCC
1
NPCC
2
NPCC
9
Gerry Dunbar
Mark Kenny
Helen Lainis
Rob Vance
Independent Electricity System
Operator
New Brunswick Power Corporation
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
NPCC
10
NPCC
5
David Ramkalawan
Northeast Power Coordinating
Council
Ontario Power Generation, Inc.
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
Northeast Power Coordinating
Council
NextEra Energy, LLC
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
Silvia Parada Mitchell
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
41
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
NPCC
1
NPCC
1
Sylvain Clermont
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
Si Truc Phan
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Michael Forte
Brian O'Boyle
Peter Yost
NPCC
1
NPCC
8
NPCC
3
Selected Answer:
No
Answer Comment:
Regarding Requirement R1, the RAS‐entity is not typically qualified to provide
some of the information required in Attachment 1, such as Sections II.3, II.4,
II.5, and II.6. This information is typically developed by the Planning
Coordinator (PC) or Transmission Planner (TP). RAS‐owners typically only
implement the RAS as functionally required by the PC or TP. The Planning
Coordinator should be listed as an applicable entity.
The Planning Coordinator is the correct function to determine where a RAS
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
42
Scheme is required. The need for a RAS is determined from TPL studies and
planned system performance. The standard correctly provides the RC with an
opportunity to participate in providing opinion. The NERC Functional Model
defines the RC as being “The functional entity that maintains the Real‐time
operating reliability of the Bulk Electric System within a Reliability
Coordinator Area.” It is not responsible for the planning or installation of a
Protection System. The NERC Functional Model does not support the RC as
being the reviewer. The RC currently does not review nor have the authority
to approve any other facility or protection system installation. Clarification of
R3 regarding approval of the RAS after all issues have been addressed should
be made. The approval mentioned in R3 could be interpreted as an approval
that each identified outstanding issue was addressed not complete formal
approval of the RAS. If the RC is to perform the review, we suggest the
following:
R3‐ Following the review performed pursuant to Requirement R2, the RAS‐
entity shall address each issue identified by the Reliability Coordinators
participating in the review and obtain final approval(s) for the RAS from each
Reliability Coordinator participating in the review, prior to placing a new or
functionally modified RAS in service or retiring an existing RAS.
Regarding Requirement R3 some of the identified issues would be most
appropriately addressed by the PC or TP, especially the items in Section II of
Attachment 1 as mentioned earlier. It is inappropriate for the RAS‐entity to
assume compliance responsibility for addressing each identified issue. The
RAS‐owner for the RAS issues should be the responsible entity.
Response: Thank you for your comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
43
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The RAS‐entity is the best‐
suited entity to address any identified issues per Requirement R3. The drafting team maintains that the RAS‐entity has the
“flexibility” to request information or assistance from relevant entities (third parties).during the review. Any other reliability
considerations, along with their resolution with respect to the particular RAS under review, should be documented along
with the Attachment 2 items that were applicable to the specific RAS under review.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
44
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2 ‐
Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Response: Thank you for your comments.
Please see the drafting team’s responses to the referenced comments.
Mark Holman ‐ PJM Interconnection, L.L.C. ‐ 2 ‐
Selected Answer:
No
Answer Comment:
PJM supports the comments submitted by the ISO/RTO Council.
Response: Thank you for your comments.
Please see the drafting team’s responses to the referenced comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
45
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Selected Answer:
Yes
Eric Olson ‐ Transmission Agency of Northern California ‐ 1 ‐
Selected Answer:
Yes
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Selected Answer:
No
Answer Comment:
R1, R2 and R3 do not differentiate between the functional aspects and design
aspects of RAS. The functional requirements for a RAS, i.e. system conditions
and triggering contingencies for which RAS is required as well as RAS actions
to meet system performance requirement (as per TPL‐001‐4), are studied and
identified by Transmission Planner and/or Planning Coordinator and not by
the RAS owner/entity. The RAS owner/entity designs the RAS after TP or PC
determines the functional requirements. The information listed in part II of
attachment 1 is about functional requirements and can be provided by TP or
PC. Most of the information listed in part I is repeat of part II. The rest, e.g.,
maps, one‐line diagrams, in‐service date, etc., can also be provided by TP or
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
46
PC who determined the functional requirements. The information in part III,
which is related to the RAS design, is provided by the RAS owner/entity. RAS
owners typically only implement the RAS as functionally required by the PC or
TP. It is noted that the Planning Coordinator is not listed as an applicable
entity and should be. With regard to R3, some of the identified issues would
be most appropriately addressed by the PC or TP, especially the items in
Section II of Attachment 1.
We suggest that R1, R2 and R3 and the related attachments be split in two
parts: a) functional aspects, where TP or PC will be required to determine the
functional requirements of the RAS and provide relevant information to RC
for review, and b) design aspects, where RAS owner/entity will be required to
design the RAS to meet those functional requirements and provide relevant
information to RC for review.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
47
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The RAS‐entity is the best‐
suited entity to address any identified issues per Requirement R3. The drafting team maintains that the RAS‐entity has the
“flexibility” to request information or assistance from relevant entities (third parties).during the review. Any other reliability
considerations, along with their resolution with respect to the particular RAS under review, should be documented along
with the Attachment 2 items that were applicable to the specific RAS under review.
Richard Vine ‐ California ISO ‐ 2 ‐
Selected Answer:
No
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
48
Response: Thank you for your comments.
Please see the drafting team’s responses to the referenced comments.
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Selected Answer:
Yes
LCRA Compliance
Entity
Region Segments
LCRA
TRE
6
LCRA
TRE
1
LCRA
TRE
5
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
Group Member Name
Michael Shaw
Teresa Cantwell
Dixie Wells
Selected Answer:
49
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP
Group Name:
Group Member Name
Shannon Mickens
Jason Smith
James Nail
Selected Answer:
Answer Comment:
SPP Standards Review Group
Entity
Region Segments
Southwest Power Pool Inc.
SPP
2
Southwest Power Pool Inc
SPP
2
City of Independence, Missouri
SPP
3,5
Yes
We agree with the checklist for the Reliability Coordinator to receive the
proper information pertaining to the RAS and conducting a proper analysis.
Additionally, we commend the drafting team for addressing the timing
requirements in the Requirement R3 Rationale Box. We feel this will give the
industry amply of enough time to address any issues identified by the
Reliability Coordinator through their analysis.
Response: Thank you for your support.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
50
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
No
Answer Comment:
Florida Power and Light appreciates the efforts of the Standard Drafting Team
in consolidating the exsiting RAS‐related Standards into one Standard ‐ PRC‐
012‐2, however we disagree with the assertion that the Reliability
Coordinator (RC) is the best choice to review the RAS's for new and continued
implementation. The RC is responsible for the operation rather than the
planning of the BES. RAS design and approval is best done at the Planning
level. The Planning Coordinator is responsible for coordinating transmission
plans and protection systems and we believe more appropriate to review,
approve, and maintain the RAS database.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
51
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Selected Answer:
Yes
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Jeff Wells ‐ Grand River Dam Authority ‐ 3 ‐
Selected Answer:
Yes
52
Selected Answer:
Yes
Answer Comment:
In Requirement R3, the term “shall address” does not necessarily indicate the
issue must be resolved as the Supplemental Material indicates. Texas RE
recommends strengthening the requirement language to “shall resolve” or
“shall implement”.
Response: Thank you for your comment.
The drafting team made the suggested change.
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
No
Answer Comment:
1. RAS review should be conducted by the Planning Coordinator and not the
Reliability Coordinator. Oversight of the wide‐area in the planning horizon is
the job of the Planning Coordinator. This will be a significant amount of extra
work for the RCs who should be focused on near‐term operational reliability.
2. R1 should state a time frame the data should be submitted to the RC, such
as four month prior to implementation of the RAS. Otherwise, the burden
will be placed on the RC to conduct the study on the RAS‐entities schedule.
3. There is no requirement to notify impacted neighboring entities. When a
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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53
RAS is implemented it can have a significant impact on neighboring
entities. Neighboring entities need to have an opportunity to study the
impact of the RAS.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
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54
The drafting team maintains that it is not necessary to specify how far in advance of implementation the RAS‐entity must
provide Attachment 1 data to the reviewing RC. Expeditious submittal of this information is in the interest of each RAS‐entity
to effect a timely implementation.
As noted above, the need for a RAS and/or the determination of RAS characteristics are most often identified through
planning studies performed by the Planning Coordinators or Transmission Planners. The drafting team contends that other
Reliability Standards such TPL‐001‐4 provide avenues for neighboring entities to be notified well in advance of a new or
modified RAS being implemented.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1 ‐
Selected Answer:
No
Answer Comment:
R1, R2 and R3 do not differentiate between the functional aspects and design
aspects of RAS. The functional requirements for a RAS, i.e. system conditions
and triggering contingencies for which RAS is required as well as RAS actions
to meet system performance requirements (as per TPL‐001‐4), are studied
and identified by the TP and/or PC and not by the RAS owner/entity. The
RAS owner/entity designs the RAS after the TP or PC determines its functional
requirements. Therefore, the information listed in part II of attachment 1 is
about functional requirements and can only be provided by a TP or PC in
most instances.
Most of the information listed in Part I is repeated in Part II. The remaining
information listed, e.g., maps, one‐line diagrams, in‐service date, etc., can
also be provided by the TP or PC, who determines the functional
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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55
requirements. The information in Part III, which is related to the RAS design,
is provided by the RAS owner/entity.
Hydro One Networks Inc. suggests that R1, R2 and R3 and the related
attachments be split in two parts: a) functional aspects, where the TP or PC
will be required to determine the functional requirements of the RAS and
provide relevant information to the RC for review, and b) design aspects,
where the RAS owner/entity will be required to design the RAS to meet those
functional requirements and provide relevant information to the RC for
review.
In addition, it is inappropriate for the RAS entity to assume compliance
responsibility for addressing each identified issue. The RAS owner for the RAS
issues should be the responsible entity; this would be more in agreement
with the assignment of accountabilities in R6.
Please also note our following comments with respect to relaxing the design
review for a class of RAS.
Response: Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often
identified through planning studies performed by the Planning Coordinators or Transmission Planners. These studies are
included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review and approval.
Consequently, the drafting team contends that mandating the Planning Coordinator to participate in the RAS approval
process is unnecessary and declines to make the suggested change. As the drafting team stated in the Rationale and
Supplemental Materials section of the standard, the RC has the “flexibility” to request information or assistance from
relevant entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the
review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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56
equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this
flexibility allows the RC to perform a more robust review.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The RAS‐entity is the best‐
suited entity to address any identified issues per Requirement R3. The drafting team maintains that the RAS‐entity has the
“flexibility” to request information or assistance from relevant entities (third parties).during the review. Any other reliability
considerations, along with their resolution with respect to the particular RAS under review, should be documented along
with the Attachment 2 items that were applicable to the specific RAS under review.
Likes:
Dislikes:
1
Hydro One Networks, Inc., 3, Malozewski Paul
0
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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57
Group Name:
Group Member Name
Tim Beyrle
Jim Howard
Lynne Mila
Javier Cisneros
Randy Hahn
Don Cuevas
Stan Rzad
Matt Culverhouse
Tom Reedy
Steven Lancaster
Mike Blough
Mark Brown
Mace Hunter
Selected Answer:
FMPA
Entity
Region Segments
City of New Smyrna Beach
FRCC 4
Lakeland Electric
FRCC 3
City of Clewiston
FRCC 3
Fort Pierce Utility Authority
FRCC 4
Ocala Utility Services
FRCC 3
Beaches Energy Services
FRCC 1
Keys Energy Services
FRCC 4
City of Bartow
FRCC 3
Florida Municipal Power Pool
FRCC 6
Beaches Energy Services
FRCC 3
Kissimmee Utility Authority
FRCC 5
City of Winter Park
FRCC 3
Lakeland Electric
FRCC 3
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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58
Answer Comment:
R2 has an option of a four month schedule or a mutually agreed upon
schedule. It is understood that setting a goal for a review within the
operations time‐frame is important, but it seems like the standard is trying to
achieve two separate goals at once.
The first goal is to review the proposed change to determine whether it
involves a CAP and identifies any current risks to reliability of the system
which, as identified in the standard, might require use of System operating
limits until the CAP is complete. This review needs to be completed quickly to
minimize risk to the BES, but requires much less effort than a full review of
the performance of the new RAS. In this instance four full‐calendar months
would seem to be too long of a time period.
The second goal is to complete the full review from a planning
perspective. Each region already has a review and approval process in
place. It seems arbitrary and unnecessary to impose the 4 month
requirement rather than allowing the RC to follow a schedule or process it
has already established. In this instance the four months would seem too
short a time period in many cases due to the way these reviews are
conducted (and by whom they are conducted) – so long as the risk to the BES
reliability is already understood up‐front, there is no reason to rush this
portion of the work. In many cases, the RC in question may not possess the
necessary staff / skills to perform what is required in Attachment 2, and may
need to retain the services of others (consultants or perhaps area PCs or TPs),
which will take time.
FMPA believes both issues could be resolved if R2 separated the near‐term
need to quickly assess BES reliability risk in the Operating Horizon from the
long‐term need to assess the details of the performance of the proposed
scheme – particularly in cases where the proposed change is due to an
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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59
identified issue with a subsequent CAP. Doing this first step on fast track
would then allow each RC to define the schedule for the remaining review as
per their regional practices.
Also, it would be beneficial to include all RAS‐owners and their contact
information in the RAS database.
Response: Thank you for your comments.
The time frame of four full calendar months is consistent with current utility and regional practices. The drafting team wrote
the requirement to allow for time intervals longer or shorter than four full calendar months by including the phrase
"mutually agreed upon schedule" among the affected parties. The RAS review associated with a CAP could and probably
would require less than the four full calendar months. The drafting team disagrees that there is a reliability risk during the
time interval associated with the CAP development though completion of the CAP because the Reliability Coordinator will
require the RAS‐entity to modify operating procedures, System configuration, generation dispatch, or employ other methods
to alleviate the deficient RAS. The RAS review associated with new or functionally modified RAS is a more comprehensive
review that entail the design, operations, and testing of the RAS. The drafting team declines to make the suggested change.
The drafting team modified the description of RAS‐entity and eliminated RAS‐owner. With this revised description, each RAS‐
entity (Transmission Owner, Generator Owner, or Distribution Provider) will be specifically identified in Attachments 1 and 3.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
ACES Standards Collaborators
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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60
Group Member Name
Entity
Region Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
Prairie Power, Inc.
RFC
1
SERC
1,3
SPP
1
Ginger Mercier
Ellen Watkins
Michael Brytowski
Shari Heino
John Shaver
John Shaver
Sunflower Electric Power
Corporation
Great River Energy
Brazos Electric Power Cooperative,
Inc.
Arizona Electric Power Cooperative,
Inc.
Southwest Transmission
Cooperative, Inc.
MRO
1,3,5,6
TRE
1,5
WECC
4,5
WECC
1
Selected Answer:
No
Answer Comment:
(1) We question why the RC was selected as the reviewing entity in this
context. RC System Operators are not required to be “familiar with”
(Reliability Standard PRC‐001) or “have knowledge of” (proposed Reliability
Standard TOP‐009) the purpose and limitations of a RAS. Moreover, after the
RC has conducted its initial review (Requirement R2) and the RAS‐entity has
addressed the identified issues, there is no timeframe required for the RC to
conduct a final review for approval. We suggest rewording Requirement R3
to require both the RAS‐entity and the RC to address each identified issue
within a mutually agreed upon timeframe and concluded by a final RC
review. Documentation regarding an approval of the RC following its final
review should then be listed as acceptable evidence in Measure M3.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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61
(2) We would also like the drafting team to state that an existing SPS will not
need to go through the RC approval process even though the new definition
of RAS could be applied as a new RAS device. The standard is unclear
regarding which equipment will need to go through the RC approval process,
existing SPS/RAS or new/changed RAS equipment? One possible solution is
to state that all SPS and RAS equipment that are in service on the effective
date of the proposed standard are considered RAS going forward and will not
be required to go through the RC approval process.
Response: Thank you for your comment.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS
reviews because the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. The RC is also more likely to be independent of the entities involved in planning and
implementing the RAS. The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess
more information or ability than anticipated by their functional registration as designated by NERC. The NERC Functional
Model is a guideline for the development of standards and their applicability and does not have compliance requirements.
The drafting team is not precluded from developing Reliability Standards that address functions not described in the model.
Reliability Standard requirements take precedence over the Functional Model. For reference, please see the Introduction
section of NERC’s Reliability Functional Model, Version 5, November 2009. As the drafting team stated in the Rationale and
Supplemental Material section of the standard, the RC has the “flexibility” to request information or assistance from relevant
entities (third parties) to participate in the review if they believe it will enhance the quality and efficiency of the review
process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is not equipped
to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this flexibility
allows the RC to perform a more robust review.
The drafting team maintains that it is not necessary to specify how far in advance of implementation the RAS‐entity must
provide Attachment 1 data to the reviewing RC. Expeditious submittal of this information is in the interest of each RAS‐entity
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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62
to effect a timely implementation. In turn, the RC is well aware of the issues that the RAS is intended to solve, as well as the
implications to the RAS‐entity’s schedule for delays. It is in the interest of the reviewing RC to expeditiously acknowledge
when reliability issues are resolved so that the larger solution (the RAS) can be implemented. The drafting team declines to
make the suggested change to the Requirement R3.
Requirement 1 is applicable to new or functionally modified RAS. Existing RAS will not need to go through the RC approval
process unless they require functional modification. The drafting team declines to make the suggested change.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
No
Answer Comment:
BPA believes R2’s timeline of four‐full‐calendar months for RC review of RAS
submission is too generous; it is inconsistent with regional practice. BPA
proposes two weeks as appropriate, with less potential negative impact. The
schedule should be short enough to accommodate the needs of the RAS
owners and the “mutually agreed upon schedule” should apply if more time is
needed.
Response: Thank you for your comment.
The time frame of four full calendar months is consistent with current utility and regional practices. The drafting team wrote
the requirement to allow for time intervals longer or shorter than four full calendar months by including the phrase
"mutually agreed upon schedule" among the affected parties. The drafting team declines to make the suggested change.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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63
Requirement R4 mandates that the Transmission Planner perform a technical evaluation (planning analyses) of each RAS at
least once every 60 full calendar months to verify the continued effectiveness and coordination of the RAS, including BES
performance following an inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to these
topics.
2. RAS Periodic Evaluations: Do you agree with the RAS planning evaluation process outlined by Requirement R4? If no, please
provide the basis for your disagreement and an alternate proposal.
Selected Answer:
Yes
Barbara Kedrowski ‐ WEC Energy Group, Inc. ‐ 3,4,5,6 ‐ RFC
Selected Answer:
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Yes
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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64
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Amy Casucelli
Xcel Energy
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Theresa Allard
Minnkota Power Cooperative, Inc
Dave Rudolph
Basin Electric Power Cooperative
Kayleigh Wilkerson
Lincoln Electric System
Jodi Jenson
Western Area Power
Administration
Larry Heckert
Alliant Energy
Mahmood Safi
Omaha Public Utility District
Shannon Weaver
Midwest ISO Inc.
Mike Brytowski
Great River Energy
Brad Perrett
Minnesota Power
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1,3,5,6
MRO
1
MRO
1,3,5
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,6
MRO
4
MRO
1,3,5,6
MRO
2
MRO
1,3,5,6
MRO
1,5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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65
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
MRO
1,3,5
Selected Answer:
No
Answer Comment:
For R4, we propose revised wording to explicitly include any applicable
Planning Coordinators with wording like, “. . . provide the results
including any identified deficiencies to the RAS‐owner(s), the reviewing
Reliability Coordinators(s) and impacted Transmission Planners and
Planning Coordinators.”
Again, the inclusion of impacted Transmission Planners and Planning
Coordinators is appropriate because these entities will generally have
the best planning horizon information and expertise to review the
evaluation.
Response: Thank you for your comments.
The drafting team revised the requirement to make the Planning Coordinator the responsible entity for performing
the periodic evaluations.
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66
Selected Answer:
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Yes
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC
Group Name:
Group Member Name
Pawel Krupa
Dana Wheelock
Hao Li
Bud (Charles) Freeman
Mike haynes
Michael Watkins
Faz Kasraie
John Clark
Selected Answer:
Seattle City Light Ballot Body
Entity
Regio
n
Seattle City Light
WECC
Segme
nts
1
Seattle City Light
WECC 3
Seattle City Light
WECC 4
Seattle City Light
WECC 6
Seattle City Light
WECC 5
Seattle City Light
WECC 1,3,4
Seattle City Light
WECC 5
Seattle City Light
WECC 6
Yes
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67
Chris Scanlon ‐ Exelon ‐ 1 ‐
Group Name:
Group Member Name
Chris Scanlon
John Bee
Selected Answer:
Exelon Utilities
Entity
Regio
n
BGE, ComEd, PECO TO's
RFC
Segme
nts
1
3
BGE, ComEd, PECO LSE's
RFC
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
We agree the Transmission Planner should periodically evaluate each
RAS but there needs to be a mechanism by which the RAS‐owners are
required to share the RAS information with the Transmission Planner.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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Yes
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Selected Answer:
Response: Thank you for your comment.
The drafting team revised the requirement to make the Planning Coordinator (PC) the responsible entity for
performing the periodic evaluations and requiring the PC to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity.
Yes
Jeri Freimuth ‐ APS ‐ Arizona Public Service Co. ‐ 3 ‐
Selected Answer:
No
Answer Comment:
The process is not clear about the responsibility for a RAS which is
activated in multiple Transmission Planner areas such as WECC‐1. The
standard should clearly specify whose responsibility it is to perform
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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69
technical studies. APS suggests the following language:
“For a RAS which is activated in multiple Transmission Planning areas, a
mutually agreed upon Transmission Planner of one of the multiple
Transmission Planning areas shall perform an evaluation of the RAS at
least once every 60‐full‐calendar‐months and provide the RAS‐owner(s)
and the reviewing Reliability Coordinator(s) the results including any
identified deficiencies.”
Response: Thank you for your comment.
The drafting team revised the requirement to make the Planning Coordinator (PC) the responsible entity for
performing the periodic evaluations. The drafting team notes that the existing wording of the requirement allows the
individual PCs to perform the evaluation of RAS within its own planning area, and also allows coordination of all
relevant PCs to perform a joint evaluation of RAS that span multiple PC areas.
Maryclaire Yatsko ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5,6 ‐ FRCC
Selected Answer:
No
Answer Comment:
a. For R4, can the TP merely provide the data to the RAS owners and
the RAS‐entity report the information to the RC?
b. In R4.2, please give additional detail as to what “adverse
interactions” cover?
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Response: Thank you for your comment.
The drafting team asserts that the results of the periodic evaluation should go directly to the Reliability Coordinator
because if there is a deficiency identified in the RAS functionality, a change in System operations may be required.
The drafting team maintains that adverse interactions covers inadvertently activating other RAS, mis‐coordinating
with Protection Systems or control systems.
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP
Selected Answer:
No
Answer Comment:
The rationale and/or technical guidance does not make a convincing
case for why the periodic evaluation of RAS must be a planning horizon
analysis, and thus suited to be performed by Transmission Planner. As
currently drafted, R4 seems to have an underlying premise that the
periodic evaluation needs to be performed for the near‐term planning
horizon, which makes the periodic evaluation akin to the typical (future
year) planning studies performed by Transmission Planner. However,
the rationale for R4 does not provide any justification for the above. In
fact, performing a planning horizon analysis is inconsistent with, if not
contradictory to, the following reliability need stated in the rationale “A
periodic evaluation is needed because (material) changes in system
topology or operating conditions that have occurred since the previous
RAS evaluation – or initial review – was completed…” Doesn’t this imply
that the periodic RAS evaluation is for past changes, not the future
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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planned changes? If so, wouldn’t the periodic RAS evaluation be more
akin to Operational Planning Analysis (OPA) in the operating horizon? Is
there a reason why an OPA would not be able to comprehensively
address items 4.1 – 4.4 required for periodic RAS evaluation? We note
that the existing R4 rationale makes an inadequate claim that “items
required to be addressed in the evaluation are planning analyses”,
which is a weak basis for concluding that “consequently, the
Transmission Planner is the functional entity best suited to perform the
analyses.” Based on all the above reasons, we contend that the
reliability objectives of periodic RAS evaluation are more effectively
achieved based on an operating horizon analysis like OPA. Therefore,
the periodic RAS evaluation lends itself better to be performed by the
Transmission Operator (or perhaps even the Reliability Coordinator).
Response: Thank you for your comment.
The evaluation in Requirement R4 is intended to verify the effectiveness and coordination of the RAS for the current
System conditions as well as to verify that, if a RAS single component failure or single component malfunction were
to occur, requirements for BES performance would continue to be satisfied. Operational Planning Analysis (OPA), by
definition, look forward rather than backwards. The drafting team declines to make the suggested change.
Molly Devine ‐ IDACORP ‐ Idaho Power Company ‐ 1 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Response: Please see the drafting team’s responses to the referenced comments.
David Greene ‐ SERC ‐ 1,10 ‐ SERC
Group Name:
SERC PCS
Group Member Name
Entity
Regio
n
Segme
nts
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73
Steve Edwards
Dominion
SERC
1
Joel Masters
SCE&G
SERC
1
David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Selected Answer:
Yes
Answer Comment:
Suggest clarifying in R4 that the evaluation is a technical evaluation as
stated below:
Each Transmission Planner shall perform a technical evaluation
(planning analyses) of each RAS within its planning area at least once
every 60‐full‐calendar‐months and provide the RAS‐owner(s) and the
reviewing Reliability Coordinator(s) the results including any identified
deficiencies.
Response: Thank you for your comment.
The drafting team declines to make the suggested change.
Bob Thomas ‐ Illinois Municipal Electric Agency ‐ 4 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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74
Selected Answer:
Yes
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Selected Answer:
No
Answer Comment:
For R4, ATC proposes revising the wording to explicitly include any
applicable Planning Coordinators with wording like, “. . . provide the
results including any identified deficiencies to the RAS‐owner(s), the
reviewing Reliability Coordinators(s) and any applicable Planning
Coordinators.”
Again, the inclusion of Planning Coordinators is appropriate because the
Transmission Planner evaluation will be for the planning horizon and
Planning Coordinators will generally have the best information and
expertise to review the evaluation.
Response: Thank you for your comments.
The drafting team revised the requirement to make the Planning Coordinator the responsible entity for performing
the periodic evaluations.
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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75
Selected Answer:
No
Answer Comment:
The RAS‐entity would be more appropriate to be specified in R4 instead
of the RAS‐owner
Response: Thank you for your comment.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS.
Yes
No
Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Selected Answer:
Answer Comment:
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
The RAS‐entity would be more appropriate to be specified in R4 instead
of the RAS‐owner.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
76
Response: Thank you for your comment.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS.
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Southern Company
Entity
Regio
n
Southern Company Services, Inc.
SERC
Segme
nts
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation
and Energy Marketing
SERC
6
Yes
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
77
Selected Answer:
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Selected Answer:
Yes
Yes
David Kiguel ‐ David Kiguel ‐ 8 ‐
Selected Answer:
No
Answer Comment:
While generally supportive of this standard, I have concerns over
assigning longer term assessment to Transmission Planner rather than
to the Planning Coordinator.
Response: Thank you for your comment.
The drafting team revised the requirement and the Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4. The PC is the functional entity best suited to perform this evaluation
because they have a wide‐area planning perspective.
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78
Mike ONeil ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐
Selected Answer:
Yes
Anthony Jablonski ‐ ReliabilityFirst ‐ 10 ‐
Selected Answer:
No
Answer Comment:
1.
i. It is unclear why the Transmission Planner would provide results of
the evaluation to each of the RAS‐owner(s) and not the RAS‐entity. A
RAS typically operates as a single scheme and thus the RAS‐entity can
coordinate with all the RAS‐owners regarding such evaluation results.
ii. ReliabilityFirst currently reviews each SPS at least once every five
years for compliance with our Regional Criteria in accordance with fill‐
in‐the‐blank NERC standard PRC‐012, Requirement R1. ReliabilityFirst
has concerns with the 60 month review cycle in Requirement R4 as
there may be instances in which a SPS which was reviewed by RF in the
2000 timeframe could theoretically not be reviewed until the 2020
timeframe. ReliabilityFirst believes a potential gap of 10 years in
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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79
between reviews may have reliability impact. In order to prevent such a
potential gap, ReliabilityFirst recommends the following
recommendation for consideration:
a. Each Transmission Planner shall perform an evaluation of each
RAS within its planning area at least once every 60‐full‐calendar‐months
[since its last evaluation] and provide the RAS‐owner(s) and the
reviewing Reliability Coordinator(s) the results including any identified
deficiencies. Each evaluation shall determine whether:
Response: Thank you for your comment.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and the RAS‐entity will be provided the results by the PC. The PC is the
functional entity best suited to perform this evaluation because they have a wide‐area planning perspective.
The drafting team disagrees that there will be any reliability impact during the transition period. The analyses
required in Requirement R5 for all operations of the RAS will provide the reliability assurance you reference.
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐
Group Name:
IRC Standards Review Committee
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80
Group Member Name
Entity
Regio
n
Charles Yeung
SPP
SPP
Ben Li
IESO
NPCC
Greg Campoli
NYISO
NPCC
Mark Holman
PJM
RFC
Matt Goldberg
ISONE
NPCC
Lori Spence
MISO
MRO
Christina Bigelow
ERCOT
TRE
Ali Miremadi
CAISO
WECC
Segme
nts
2
2
2
2
2
2
2
2
Selected Answer:
No
Answer Comment:
Many Transmission Owner organizations also perform the transmission
planning function and as such, are also registered as the Transmission
Planners (for the assets that they own). The SRC believes that a proper,
unbiased evaluation of RAS performance should be conducted by an
entity that is not in the same organization as the TO and has a broader
perspective, which is important because RAS’s intended function and
operational impact may affect more than one TO and TP. The SRC
respectfully asserts that, given the importance of independence and a
wide‐area perspective, the Planning Coordinator is a more appropriate
entity to perform Requirement R4 . The SRC therefore suggests
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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81
replacing the TP with the PC or, at a minimum, requiring a review of
results and provision of feedback by the Planning Coordinator to the
Transmission Planner. This proposal is consistent with the basis for
assigning R2 to the RC rather than the TOP.
Response: Thank you for your comment.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Response: Please see the drafting team’s response to the referenced comment.
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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82
Selected Answer:
No
Answer Comment:
The RAS‐entity would be more appropriate to be specified in R4 instead
of the RAS‐owner.
The RAS‐entity and the RAS‐owner should be provided with the result
of the review. The PC may be more appropriately qualified to review
certain RAS than the TP.
Response: Thank you for your comment.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio
n
Segme
nts
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83
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Selected Answer:
Yes
Answer Comment:
Dominion suggests clarifying in R4 that the evaluation is a technical
evaluation as stated below:
Each Transmission Planner shall perform a technical evaluation
(planning analyses) evaluation of each RAS within its planning area at
least once every 60‐full‐calendar‐months and provide the RAS‐owner(s)
and the reviewing Reliability Coordinator(s) the results including any
identified deficiencies.
Response: Thank you for your comment.
The drafting team declines to make the suggested change.
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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84
Group Member Name
Entity
Joseph Smith
Public Service Electric and Gas
Jeffrey Mueller
Public Service Electric and Gas Co.
Tim Kucey
PSEG Fossil LLC
Karla Jara
PSEG Energy Resources & Trade
LLC
Regio
n
RFC
Segme
nts
1
RFC
3
RFC
5
RFC
6
Selected Answer:
No
Answer Comment:
R4 should be modified to include a new part 4.5 that would require the
Transmission Planner to identify any performance deficiencies in the
RAS as well as alternatives for mitigating or correcting such
deficiencies. The RAS‐owners would not have the capability to identify
alternatives for correcting deficiencies.
Response: Thank you for your comment.
The drafting team revised the requirement to make the Planning Coordinator (PC) the responsible entity for
performing the periodic evaluations and requiring the PC to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity.
Requirements R6 mandates the RAS‐entity develop a Corrective Action Plan. If the RAS‐entity needs assistance, it can
engage its Transmission Planner or Planning Coordinator. The drafting team declines to make your suggested change.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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85
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Group Name:
FE RBB
Group Member Name
William Smith
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Selected Answer:
Yes
Entity
Regio
n
FirstenergyCorp
RFC
Segme
nts
1
FirstEnergy Corp.
RFC
3
Ohio Edison
RFC
4
FirstEnergy Solutions
RFC
5
FirstenergyCorp
RFC
NA
FirstEnergy Solutions
FRCC
6
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86
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Alan Adamson
New York State Reliability Council,
LLC
David Burke
Orange and Rockland Utilities Inc.
Greg Campoli
New York Independent System
Operator
Gerry Dunbar
Northeast Power Coordinating
Council
Mark Kenny
Northeast Utilities
Helen Lainis
Independent Electricity System
Operator
Rob Vance
New Brunswick Power Corporation
Paul Malozewski
Hydro One Networks Inc.
Bruce Metruck
New York Power Authority
Lee Pedowicz
Northeast Power Coordinating
Council
David Ramkalawan
Ontario Power Generation, Inc.
Regio
n
NPCC
Segme
nts
10
NPCC
3
NPCC
2
NPCC
10
NPCC
1
NPCC
2
NPCC
9
NPCC
1
NPCC
6
NPCC
10
NPCC
5
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87
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
Silvia Parada Mitchell
Northeast Power Coordinating
Council
NextEra Energy, LLC
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
NPCC
1
NPCC
1
Sylvain Clermont
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
Si Truc Phan
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Michael Forte
Brian O'Boyle
Peter Yost
NPCC
1
NPCC
8
NPCC
3
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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88
Selected Answer:
No
Answer Comment:
It would be more appropriate to specify the RAS‐entity in R4 instead of
the RAS‐owner.
The RAS‐entity and the RAS‐owner should be provided with the results
of the review. The PC may be more appropriately qualified to review
certain RAS than the TP. Consider revising R4 to read “Each
Transmission Planner shall evaluate…”
Add wording to the Rationale for Requirement R4 to clarify that the
intent is not to evaluate all RAS at the same time, but that each RAS is
to be evaluated on a 60 full calendar month cycle.
Would the Planning Coordinator ever perform this evaluation instead of
the Transmission Planner?
Response: Thank you for your comment.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective. Please see the
complementary revisions to the Rationale boxes and Supplemental Material section of the draft standard.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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89
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2 ‐
Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Response: Please see the drafting team’s responses to the referenced comments.
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Mark Holman ‐ PJM Interconnection, L.L.C. ‐ 2 ‐
Selected Answer:
No
Answer Comment:
PJM supports the comments submitted by the ISO/RTO Council.
Response: Please see the drafting team’s responses to the referenced comments.
90
Selected Answer:
No
Answer Comment:
How would a scenario be addressed in which a RAS spans two or more
Transmission Planner areas?
Response: Thank you for your comment.
The drafting team revised the requirement to make the Planning Coordinator (PC) the responsible entity for
performing the periodic evaluations. The drafting team notes that the existing wording of the requirement allows the
individual PCs to perform the evaluation of RAS within its own planning area, and also allows coordination of all
relevant PCs to perform a joint evaluation of RAS that span multiple PC areas. The PC is the functional entity best
suited to perform this evaluation because they have a wide‐area planning perspective.
Eric Olson ‐ Transmission Agency of Northern California ‐ 1 ‐
Selected Answer:
No
Answer Comment:
TANC has concerns with the current language in R4 because appears to
assume that a RAS exists within a single planning area. NERC has not
defined the term “planning area”, which creates ambiguity in the
requirement’s language that states “Each Transmission Planner shall
perform an evaluation of each RAS within its planning area.” This
ambiguity is further compounded in circumstances where a single RAS
exists within the footprints of multiple Transmission Planners (and
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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91
Planning Coordinators). In such cases, it is unclear which Transmission
Planners associated with the multiple RAS‐owners for a single RAS
would have responsibility in accordance with this standard.
Response: Thank you for your comment.
The drafting team revised the requirement to make the Planning Coordinator (PC) the responsible entity for
performing the periodic evaluations. The drafting team notes that the existing wording of the requirement allows the
individual PCs to perform the evaluation of RAS within its own planning area, and also allows coordination of all
relevant PCs to perform a joint evaluation of RAS that span multiple PC areas.
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Selected Answer:
No
Answer Comment:
We generally agree with the process outlined by R4, but reiterate our
comment that the Planning Coordinator, NOT the TP, should the entity
responsible for this requirement.
Many Transmission Owner organizations also perform the transmission
planning function and as such, are also registered as the Transmission
Planners (for the assets that they own). A proper and unbiased
evaluation of the RAS performance should be conducted by an entity
that is not in the same organization as the TO and has a wider
perspective than the TO and TP. And since the RAS intended function its
operational impact may affect more than one TOs and TPs, a PC is the
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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92
most appropriate entity to perform this task than the TP, both from an
independence and a wide area perspectives. We therefore suggest
replacing the TP with the PC. This proposal is consistent with the basis
for assigning R2 to the RC rather than the TOP.
The RAS‐entity and the RAS‐owner should be provided with the result of
the review. The PC may be more appropriately qualified to review
certain RAS than the TP.
Response: Thank you for your comment.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
Richard Vine ‐ California ISO ‐ 2 ‐
Selected Answer:
No
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards
Review Committee
Response: Please see the drafting team’s responses to the referenced comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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Yes
Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
Group Member Name
Michael Shaw
Teresa Cantwell
Dixie Wells
Selected Answer:
Answer Comment:
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Selected Answer:
LCRA Compliance
Entity
Regio
n
LCRA
TRE
Segme
nts
6
LCRA
TRE
1
LCRA
TRE
5
No
To address existing entity NERC registration in the ERCOT region,
“Transmission Planner” should be replaced with “Transmission Planner
(in the ERCOT Region this applies to the Planning Authority and /or
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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94
Reliability Coordinator.)”
R4. Each Transmission Planner (in the ERCOT Region this applies to the
Planning Authority and /or Reliability Coordinator) shall perform an
evaluation of each RAS within its planning area at least once every 60‐
full‐calendar‐months and provide the RAS‐owner(s) and the reviewing
Reliability Coordinator(s) the results including any identified
deficiencies. Each evaluation shall determine whether: [Violation Risk
Factor: Medium] [Time Horizon: Long‐term Planning]
Response: Thank you for your comment.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP
Group Name:
SPP Standards Review Group
Group Member Name
Entity
Regio
n
Shannon Mickens
Southwest Power Pool Inc.
SPP
Segme
nts
2
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95
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Selected Answer:
Yes
Answer Comment:
We feel that the Transmission Planner also conducting an analysis will
help address changes to the RAS which could impact the BES.
Additionally, we like the fact that the analysis can be performed earlier
if changes to the systems topology or system operating conditions has a
potential impact on the BES (as mentioned in the second paragraph of
the Rationale Box for Requirement R4).
Response: Thank you for your comments.
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Yes
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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96
Selected Answer:
Yes
Jeff Wells ‐ Grand River Dam Authority ‐ 3 ‐
Selected Answer:
Yes
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Selected Answer:
No
Answer Comment:
Texas RE asks the drafting team to consider adding the Planning
Coordinator to Requirement R4 for instances where a RAS covers
multiple Transmission Planner areas. The current practice the ERCOT
region is ERCOT conducts the 5‐year review of each RAS; however,
ERCOT is the Planning Coordinator, not a Transmission Planner.
Texas RE asks the drafting about the term “60‐full‐calendar‐months” in
Requirements R4 and R6. The term is not defined and is not consistent
with other standards and requirements. PRC‐006 indicates five years,
PRC‐010‐1 indicates 60 calendar months, and PRC‐014 indicates five
years. Texas RE recommends not introducing new terms and to be as
consistent as possible. Is the SDT defining a “full calendar month” or
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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97
“calendar year”? The RSAW is not the place to define a new term and
the definition is different than terms used in PRC‐005. This definition is
misleading to those reviewing the document and could potentially
exacerbate reliability issues nearly seven years based on the
“definition” provided in the Note to Auditor section of R4 in the RSAW.
The intent of Requirement R9 should be to update once per year not
once per 729 days (2 years minus 1 day) which would be allowable by
the definition of full calendar year as stated in the RSAW.
Texas RE recommends defining the term “planning area”. It should be
prescriptive enough to include GOs and DPs that are RAS‐owners, i.e.
generator owners or distribution providers that own all or part of a RAS.
In Requirement R4, by default a Generator Owner or Distribution
Provider owned RAS would be within a Transmission Planners planning
area, correct? Please confirm or give specifics as to why a GO or DP
owned RAS would not be within a Transmission Planners planning area.
Response: Thank you for your comment.
The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
The drafting team uses the clarifier “full” to be clear that partial months are not counted. For example, if the starting
point is in the middle of a calendar month, the entity will have until the end of the last month of the stated period.
The drafting team revised the language to “at least once every 12‐full calendar months”.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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The drafting team maintains that the term “planning area” is generally understood throughout the industry and
declines to attempt to define it in this standard.
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
No
Answer Comment:
The RAS owner must review the RASs in R4, R5, R6. Nowhere does it
give the reviewing Reliability Coordinator the authority to dispute the
evaluation in R4, dispute the analysis in R5, and require changes to the
corrective action plan in R6. RC is just provided the results of analysis
but is not given any authority to do anything with them.
Response: Thank you for your comment.
The drafting team agrees that the Reliability Coordinator is provided the results of the requirements you mention
and the drafting team maintains that is sufficient. The Reliability Coordinator is already responsible for the reliability
of its RC Area and has the authority to address any reliability concern through other standards.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1 ‐
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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99
Answer Comment:
Although Hydro One Networks Inc. agrees with the evaluation process,
we emphasize (as described above in Q1) that the evaluation of each
new RAS must also be required from the TP or PC before the RAS is
approved and implemented by the RAS owner/entity. We recognize
that it is inconsistent to require the initial assessment of a RAS from a
RAS owner/entity (in R1), and the subsequent/periodic assessments
from a TP (in R4).
Response: Thank you for your comment.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most
often identified through planning studies performed by the Planning Coordinators or Transmission Planners. These
studies are included in the Attachment 1 information supplied to the Reliability Coordinator (RC) for the RAS review
and approval. Consequently, the drafting team contends that mandating the Planning Coordinator to participate in
the RAS approval process is unnecessary and declines to make the suggested change. As the drafting team stated in
the Rationale and Supplemental Materials section of the standard, the RC has the “flexibility” to request information
or assistance from relevant entities (third parties) to participate in the review if they believe it will enhance the
quality and efficiency of the review process. The ability of the RC to solicit assistance in performing the RAS review
does not indicate that the RC is not equipped to perform the RAS review, or that another party should be chosen to
perform the review. To the contrary, this flexibility allows the RC to perform a more robust review.
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
Group Name:
FMPA
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100
Group Member Name
Entity
Regio
n
Tim Beyrle
City of New Smyrna Beach
FRCC
Jim Howard
Lakeland Electric
FRCC
Lynne Mila
City of Clewiston
FRCC
Javier Cisneros
Fort Pierce Utility Authority
FRCC
Randy Hahn
Ocala Utility Services
FRCC
Don Cuevas
Beaches Energy Services
FRCC
Stan Rzad
Keys Energy Services
FRCC
Matt Culverhouse
City of Bartow
FRCC
Tom Reedy
Florida Municipal Power Pool
FRCC
Steven Lancaster
Beaches Energy Services
FRCC
Mike Blough
Kissimmee Utility Authority
FRCC
Mark Brown
City of Winter Park
FRCC
Mace Hunter
Lakeland Electric
FRCC
Segme
nts
4
3
3
4
3
1
4
3
6
3
5
3
3
Selected Answer:
Yes
Answer Comment:
Recommend changing 60 full calendar months to 5 calendar years, to
allow the RAS evaluation to fit within the annual Planning Assessment
process which may vary from year to year.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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101
Response: Thank you for your comment.
The drafting team based the 60 full calendar months schedule on the existing PRC‐014‐0, Requirement R1 to perform
an assessment “at least once every five year. . .” The drafting team does not see a convincing reliability reason to
further extend this schedule and declines to make the suggested change.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
ACES Standards Collaborators
Group Member Name
Entity
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
Ginger Mercier
Prairie Power, Inc.
Ellen Watkins
Sunflower Electric Power
Corporation
Michael Brytowski
Great River Energy
Shari Heino
Brazos Electric Power Cooperative,
Inc.
John Shaver
Arizona Electric Power
Cooperative, Inc.
Regio
n
RFC
Segme
nts
1
SERC
1,3
SPP
1
MRO
1,3,5,6
TRE
1,5
WECC 4,5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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102
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC 1
Selected Answer:
No
Answer Comment:
(1) We believe 60 calendar months is an appropriate amount of time
to conduct RAS periodic evaluations. However, we do not believe the
TP has sufficient visibility outside of its area to determine if the BES will
remain stable or the occurrence of a Cascading outage will be
minimized following the inadvertent operation of a RAS from any single
RAS component malfunction. These “wide‐area” views are only
available to the PC. We believe the requirement should be rewritten to
include the PC as an applicable entity for these technical evaluations.
(2) We have concerns that the requirement does not identify what
events will trigger when the clock begins on the 60 calendar month
timeframe. We ask the SDT to clarify when the clock starts for these
periodic evaluations – is it after the initial installation, after the latest
modification to RAS functionality, or following a response to a CAP?
Response: Thank you for your comments.
Based on comments, the drafting team revised the requirement. The Planning Coordinator (PC) is now the entity
responsible for the evaluation required per Requirement R4 and is required to provide the results of the RAS
evaluation to each reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC
is the functional entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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103
For existing RAS, the initial performance of the requirement must be completed within 60 full calendar months of the
effective date of PRC‐012‐2. For new or functionally modified RAS, the initial performance of the requirement must
be completed within sixty full calendar months of the RAS approval date by the reviewing RC(s). The drafting team
added language to the Implementation Plan to provide additional clarity.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
104
Requirement R4 mandates that the Transmission Planner perform a technical evaluation (planning analyses) of each RAS at
least once every 60 full calendar months to verify the continued effectiveness and coordination of the RAS, including BES
performance following an inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to these
topics.
3. RAS Inadvertent Operation: Do you agree with Requirement 4 Part 4.3 and Attachment 1 which stipulates that RAS
inadvertent operation due to a single component malfunction still satisfies the System performance requirements common to
TPL‐001‐4 P1‐P7 events listed in Parts 4.3.1‐4.3.5? (Note that this requirement remains the same as PRC‐012‐0 R1.4 except for
the allowance for designed‐in security that would prevent RAS inadvertent operation for any single component malfunction). If
no, please provide the basis for your disagreement and an alternate proposal.
Selected Answer:
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Yes
Thomas Foltz ‐ AEP ‐ 5 ‐
Selected Answer:
No
Answer Comment:
Clarity is needed in R4 as to exactly what the trigger is for the 60‐full‐
calendar‐months periodic review. Is it tied, perhaps, to the in‐service
status? In addition, rather than a 60 full month periodic review, AEP
suggests a “5 calendar year” review. This would allow flexibility for an
entity to integrate this work into its annual planning cycle.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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105
Response: Thank you for your comment.
The initial performance of the evaluation must be completed within 60 full calendar months of the effective date of
PRC‐012‐2. The successive performances are triggered by the previous evaluation date. The drafting team added
language to the Implementation Plan, rationale box, and Supplemental Material section of the standard to provide
additional clarity. The drafting team does not see any benefit in your suggestion and declines to make the change.
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Amy Casucelli
Xcel Energy
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Theresa Allard
Minnkota Power Cooperative, Inc
Dave Rudolph
Basin Electric Power Cooperative
Kayleigh Wilkerson
Lincoln Electric System
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1,3,5,6
MRO
1
MRO
1,3,5
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,3,5,6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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106
Jodi Jenson
Larry Heckert
Western Area Power
Administration
Alliant Energy
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
Selected Answer:
MRO
1,6
MRO
4
MRO
1,3,5
Yes
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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107
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC
Group Name:
Group Member Name
Pawel Krupa
Dana Wheelock
Hao Li
Bud (Charles) Freeman
Mike haynes
Michael Watkins
Faz Kasraie
John Clark
Selected Answer:
Answer Comment:
Seattle City Light Ballot Body
Entity
Regio
n
Seattle City Light
WECC
Segme
nts
1
Seattle City Light
WECC 3
Seattle City Light
WECC 4
Seattle City Light
WECC 6
Seattle City Light
WECC 5
Seattle City Light
WECC 1,3,4
Seattle City Light
WECC 5
Seattle City Light
WECC 6
No
Needs further clarification. The Transmission Planner or the group that
owns the RAS should be responsible for the evaluation, coordination
and testing of the RAS.
Response: Thank you for your comment.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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108
The drafting team revised the requirement and the Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4. The drafting team agrees that the RAS‐entity may need to be contacted by
the PC. The PC is the functional entity best suited to perform this evaluation because they have a wide‐area planning
perspective.
Chris Scanlon ‐ Exelon ‐ 1 ‐
Group Name:
Group Member Name
Chris Scanlon
John Bee
Selected Answer:
Exelon Utilities
Entity
Regio
n
BGE, ComEd, PECO TO's
RFC
Segme
nts
1
3
BGE, ComEd, PECO LSE's
RFC
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
109
Yes
Jeri Freimuth ‐ APS ‐ Arizona Public Service Co. ‐ 3 ‐
Selected Answer:
Yes
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Selected Answer:
Yes
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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110
Answer Comment:
Recommend deleting Part 4.3 since we find it hard to conceive how the
inadvertent operation of RAS can result in unacceptable system
performance when the primary motivation for installing any RAS is to
achieve acceptable system performance. We acknowledge that
inadvertent RAS operation is undesirable, but we also recognize that it
is fundamentally the same as a RAS misoperation. And therefore, any
adverse reliability impact due to inadvertent RAS operation would get
addressed in R5 during RAS operational performance
analysis. Consequently, we do not see any reliability risk, and thus no
associated compelling need, to identify the potentially unacceptable
system performance based on simulations/analyses performed for
periodic RAS evaluation using models that reflect “typical” rather than
actual operating conditions. Although we agree with the goal of a
robust RAS design that is not susceptible to RAS misoperation caused by
the malfunction of a single component, we also believe this objective is
effectively accomplished by any corrective action plan spawned by the
RAS operational performance analysis in R5.
Response: Thank you for your comment.
The drafting team maintains that it is desirable from a reliability perspective to identify potential inadvertent
operation issues in Requirement R4 rather than waiting for an incorrect operation to occur to determine whether
actual System performance was unacceptable. RAS operation when applicable system conditions are not present
may degrade system performance or pose a risk to reliability. For example, a RAS designed to shed a certain amount
of load following a loss of generation can lead to overfrequency on the System or other issues if the load is shed
without the loss of generation actually occurring. The drafting team maintains it is better to be proactive rather than
reactive from a reliability perspective and declines to make the suggested change.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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111
Yes
Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Molly Devine ‐ IDACORP ‐ Idaho Power Company ‐ 1 ‐
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Response: Please see the drafting team’s responses to the referenced comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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112
David Greene ‐ SERC ‐ 1,10 ‐ SERC
Group Name:
Group Member Name
Steve Edwards
Joel Masters
David Greene
Jammie Lee
Greg Davis
Selected Answer:
SERC PCS
Entity
Regio
n
Dominion
SERC
Segme
nts
1
SCE&G
SERC
1
SERC staff
SERC
10
MEAG
SERC
1
GTC
SERC
1
Yes
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
113
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important however and we suggest that only 4.3.1 and
4.3.2 as well as controlling system separation are the only aspects that
are needed. In Attachment 2 we agree that inadvertent operation
needs to be understood however if that inadvertent operation does not
cause one of the three significant adverse impacts to the reliability of
the BES then the RAS should not be subject to additional requirements
which likely will only have a localized effect. The addition of this
language in R 4.3.3, 4.3.4, and 4.3.5 unnecessarily may result in local
RAS to have increased design complexity, additional components which
may increase the likelihood of misoperation (decreasing the reliability
of the RAS) and excessive costs. We suggest the SDT consider that all
RAS which have a wider impact, whose inadvertent operation could
result in Cascading, System Separation or instability be subject to this
standard and its design requirements. To place these requirements as
written on all RAS would be of little or no benefit to achieving an
adequate level of reliability on the BES and based on this we would
characterize this as placing a requirement such as those removed by
Paragraph 81 in the standard. Furthermore, this could actually be a
detriment to the reliable operation of a local RAS subjecting it to
unnecessary additional design requirements.
Response: Thank you for your comment.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
114
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the
effective date of this standard that has been through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited impact by the
Reliability Coordinator during the RAS review process.
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
Yes
Answer Comment:
Consider adding 4.3.6 “Frequency Trigger Limits (FTLs) shall be within
acceptable limits as established”
Response: Thank you for your comment.
The drafting team contends that frequency trigger limits are only relevant in Reliability Standard BAL‐001‐2 and
declines to make the suggested change.
Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
115
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important; however, we suggest that 4.3.1, 4.3.2, and
controlling system separation should be the only aspects that are
needed. We do not understand the intent of 4.3.3 “applicable facility
ratings.” Is this normal, emergency, DAL (drastic action limit), etc.? In
Attachment 2, we agree that inadvertent operation needs to be
understood however if that inadvertent operation does not cause one
of the three significant adverse impacts to the reliability of the BES,
then the RAS should not be subject to additional requirements when
the inadvertent operation likely will only have a localized effect. The
addition of this unnecessary language in R 4.3.3, 4.3.4, and 4.3.5 may
result in local RAS having increased design complexity, additional
components that may increase the likelihood of misoperation
(decreasing the reliability of the RAS) and excessive costs. We suggest
the SDT consider that all RAS that have a wider impact, whose
inadvertent operation could result in Cascading, System Separation, or
instability, be subject to this standard and its design requirements. To
place these requirements as written on all RAS would be of little or no
benefit to achieving an adequate level of reliability on the BES and
based on this we would characterize this as a Paragraph 81 requirement
in the standard. Furthermore, this could actually be a detriment to the
reliable operation of a local RAS, subjecting it to unnecessary additional
design requirements.
Response: Thank you for your comment.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
116
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the
effective date of this standard that has been through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited impact by the
Reliability Coordinator during the RAS review process.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Southern Company
Entity
Regio
n
Southern Company Services, Inc.
SERC
Segme
nts
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation
and Energy Marketing
SERC
6
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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117
Yes
Mike ONeil ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐
Selected Answer:
Yes
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Selected Answer:
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Selected Answer:
Yes
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐
Group Name:
IRC Standards Review Committee
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
118
Group Member Name
Charles Yeung
SPP
Regio
n
SPP
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC 2
Selected Answer:
Entity
Segme
nts
2
Yes
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Response: Please see the drafting team’s response to the referenced comment.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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119
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important however we suggest that only 4.3.1 and 4.3.2 as
well as controlling system separation are the only aspects that are
needed. We do not understand the intent of 4.3.3 “applicable facility
ratings”. Is this normal, emergency, DAL (drastic action limit), etc.? In
Attachment 2 we agree that inadvertent operation needs to be
understood however if that inadvertent operation does not cause one
of the three significant adverse impacts to the reliability of the BES then
the RAS should not be subject to additional requirements which likely
will only have a localized effect. The addition of this language in R 4.3.3,
4.3.4, and 4.3.5 unnecessarily may result in local RAS to have increased
design complexity, additional components which may increase the
likelihood of misoperation (decreasing the reliability of the RAS) and
excessive costs. We suggest the SDT consider that all RAS which have a
wider impact, whose inadvertent operation could result in Cascading,
System Separation or instability be subject to this standard and its
design requirements. To place these requirements as written on all RAS
would be of little or no benefit to achieving an adequate level of
reliability on the BES and based on this we would characterize this as
placing a Paragraph 81 requirement in the standard. Furthermore, this
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
120
could actually be a detriment to the reliable operation of a local RAS
subjecting it to unnecessary additional design requirements.
Response: Thank you for your comment.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the
effective date of this standard that has been through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited impact by the
Reliability Coordinator during the RAS review process.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio
n
Larry Nash
Dominion Virginia Power
SERC
Louis Slade
Dominion Resources, Inc.
SERC
Connie Lowe
Dominion Resources, Inc.
RFC
Randi Heise
Dominion Resources, Inc,
NPCC
Segme
nts
1
6
3
5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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121
Selected Answer:
No
Answer Comment:
Dominion concurs with the idea of an inadvertent operations test;
however R4.3.5 transient voltage response should not be part of that
test. Preventing FIDVR is only necessary to prevent cascading due to
motor stalling (an unlikely outcome) which is addressed under
R4.3.2. Dominion believes that slow transient voltage response that
does not lead to cascading and is a customer power quality issue and
not a reliability issue.
Response: Thank you for your comment.
The drafting team disagrees with your comment. Requirement R4, Part 4.1.3.5 regarding transient voltage response
is a performance requirement common to other TPL contingencies (P1 to P7), and does not apply only to FIDVR
phenomena but any type of transient behavior that may affect stability.
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Group Member Name
Entity
Regio
n
Joseph Smith
Public Service Electric and Gas
RFC
Segme
nts
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
122
Jeffrey Mueller
Public Service Electric and Gas Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources & Trade
LLC
RFC
6
Answer Comment:
No comment.
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Group Name:
FE RBB
Group Member Name
Entity
Regio
n
William Smith
FirstenergyCorp
RFC
Cindy Stewart
FirstEnergy Corp.
RFC
Segmen
t
1
3
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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123
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA
Ann Ivanc
FirstEnergy Solutions
FRCC
6
Selected Answer:
Yes
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Alan Adamson
New York State Reliability Council,
LLC
David Burke
Orange and Rockland Utilities Inc.
Greg Campoli
New York Independent System
Operator
Gerry Dunbar
Northeast Power Coordinating
Council
Mark Kenny
Northeast Utilities
Regio
n
NPCC
Segme
nts
10
NPCC
3
NPCC
2
NPCC
10
NPCC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
124
Helen Lainis
Rob Vance
Independent Electricity System
NPCC
Operator
New Brunswick Power Corporation NPCC
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
NPCC
10
NPCC
5
2
9
David Ramkalawan
Northeast Power Coordinating
Council
Ontario Power Generation, Inc.
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
Silvia Parada Mitchell
Northeast Power Coordinating
Council
NextEra Energy, LLC
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
NPCC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
125
Brian O'Boyle
NPCC
Sylvain Clermont
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
Si Truc Phan
Peter Yost
8
NPCC
3
NPCC
1
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Selected Answer:
No
Answer Comment:
Part 4.3 addresses inadvertent operation and addresses security of the
RAS. This is important. However, we suggest that only sub‐Parts 4.3.1
and 4.3.2 as well as controlling system separation are the only aspects
that are needed. We do not understand the intent of sub‐Part 4.3.3
“applicable facility ratings”. Is this normal, emergency, DAL (drastic
action limit), etc.? In Attachment 2 we agree that inadvertent
operation needs to be understood. However, if that inadvertent
operation does not cause one of the three significant adverse impacts
to the reliability of the BES then the RAS should not be subject to
additional requirements which likely will only have a localized
effect. The addition of this language in sub‐Parts 4.3.3, 4.3.4, and 4.3.5
unnecessarily may result in local RAS to have increased design
complexity, additional components which may increase the likelihood
of misoperation (decreasing the reliability of the RAS) and excessive
costs. We suggest the SDT consider that all RAS that have a wider
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
126
impact, those whose inadvertent operation could result in Cascading,
System Separation or instability be subject to this standard and its
design requirements. To place these requirements as written on all RAS
would be of little or no benefit to achieving an adequate level of
reliability on the BES, and based on this we would characterize this as
placing a Paragraph 81 requirement in the standard. Furthermore, this
could actually be a detriment to the reliable operation of a local RAS
subjecting it to unnecessary additional design requirements.
Response: Thank you for your comment.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the
effective date of this standard that has been through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited impact by the
Reliability Coordinator during the RAS review process.
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2 ‐
Selected Answer:
Answer Comment:
Yes
ERCOT supports the comments submitted by the ISO/RTO Council.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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127
Yes
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Selected Answer:
Mark Holman ‐ PJM Interconnection, L.L.C. ‐ 2 ‐
Selected Answer:
Response: Please see the drafting team’s responses to the referenced comments.
Yes
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Selected Answer:
No
Answer Comment:
At the present time there are RAS in service that have a limited local
impact. To universally apply the same design criteria to all RAS
regardless of their impact on BES in case of an inadvertent operation
may have no cost benefit in the case of the RAS installed to address
local problems.
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128
We propose the following to be included in the standard:
An inadvertent operation in the RAS, when the RAS is intended to
operate, does not result in any of the following conditions on the BES:
1. Cascading
2. Uncontrolled System Separation
3. Instability
When the criteria mentioned above is not met a secure design will be
required.
Response: Thank you for your comment.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the
effective date of this standard that has been through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited impact by the
Reliability Coordinator during the RAS review process.
Richard Vine ‐ California ISO ‐ 2 ‐
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129
Selected Answer:
Yes
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards
Review Committee
Response: Please see the drafting team’s responses to the referenced comments.
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Selected Answer:
Yes
Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
LCRA Compliance
Group Member Name
Entity
Regio
n
Michael Shaw
LCRA
TRE
Teresa Cantwell
LCRA
TRE
Dixie Wells
LCRA
TRE
Segme
nts
6
1
5
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130
Selected Answer:
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP
Group Name:
Group Member Name
Shannon Mickens
Jason Smith
James Nail
Selected Answer:
Yes
SPP Standards Review Group
Entity
Regio
n
Southwest Power Pool Inc.
SPP
Segme
nts
2
Southwest Power Pool Inc
SPP
2
City of Independence, Missouri
SPP
3,5
Yes
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Yes
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131
Yes
Jeff Wells ‐ Grand River Dam Authority ‐ 3 ‐
Selected Answer:
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Selected Answer:
Yes
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Selected Answer:
Yes
Answer Comment:
The SDT may want to consider adding “Applicable System Operating
Limits shall not be exceeded” as a sub‐bullet to Requirement R4.3.
Response: Thank you for your comment.
The drafting team maintains that the Parts 4.1.3.1‐4.1.3.5 are aligned with similar TPL performance requirements for
contingencies P0‐P7 as well as SOLs calculated for both the planning and operating horizons. The drafting team
declines to make the suggested change.
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132
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Yes
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
Group Name:
FMPA
Group Member Name
Entity
Regio
n
Tim Beyrle
City of New Smyrna Beach
FRCC
Jim Howard
Lakeland Electric
FRCC
Lynne Mila
City of Clewiston
FRCC
Javier Cisneros
Fort Pierce Utility Authority
FRCC
Randy Hahn
Ocala Utility Services
FRCC
Don Cuevas
Beaches Energy Services
FRCC
Stan Rzad
Keys Energy Services
FRCC
Matt Culverhouse
City of Bartow
FRCC
Segme
nts
4
3
3
4
3
1
4
3
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133
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Selected Answer:
No
Answer Comment:
FMPA agrees with the intent of R4.3 – that construction of
devices/systems as an integral part of the BES should be held to same
standards as construction of physical facilities. However, we believe
there is a problem with the wording of the first sentence. It is possible
to read the first sentence to be requiring that inadvertent operation of
the RAS due to a single component malfunction be studied as a
planning event regardless of whether the system is designed to prevent
such an event from occurring. FMPA believes the intent of the language
is that items 4.3.1 through 4.3.5 only apply if single component
malfunction does actually produce an operation of the RAS. If this were
not true (e.g. if the language in R4.3 was requiring the study of the
inadvertent RAS operation against the criteria in 4.3.1 through 4.3.5
regardless of whether a single component malfunction could actually
cause the RAS to operate), the language would essentially be requiring
that TPL‐001‐4 Planning Event criteria be applied to what amounts to an
Extreme Event. This is partly because of the use of the term
“malfunction” as opposed to “failure”. This is not consistent with TPL‐
001‐4 which refers to protection system “failures”. This is an important
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134
distinction because typically protection systems are designed such that
if a component fails, it does so without issuing a false trip. A
malfunction can be interpreted to mean a large number of absurdly
unlikely things which are over and above the level of rigor required by
TPL‐001‐4. FMPA understands that the SDT desired to consider the use
of non‐“protection system” control devices using this standard, but the
language as written does not allow those entities that are using
protective devices to take credit for basic design principles such as
redundancy. Suggest either expressly allowing entities to take credit for
redundancy, switching to using the term “failure” or both.
Response: Thank you for your comment.
The drafting team agrees with the intent of the comment ‐ that 4.1.3.1‐4.1.3.5 only apply if a single component
malfunction, per the design of the RAS, can produce an inadvertent operation of the RAS (or part of the RAS). The
drafting team maintains that there are other modes of improper component operation that the term “failures” may
not clearly address, and therefore “malfunction” is a more appropriate term. Requirement R4, Part R4.1.3 maintains
consistency with existing PRC‐012‐1 Requirement R1, R1.4 regarding inadvertent operation but is meant to clarify
that design considerations to improve security can be implemented that will essentially prevent inadvertent
operation. If single component malfunction (or failure) cannot cause an inadvertent operation, 4.1.3.1‐4.1.3.5 do not
need to be assessed.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
ACES Standards Collaborators
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135
Group Member Name
Entity
Bob Solomon
Ginger Mercier
Ellen Watkins
Michael Brytowski
Shari Heino
John Shaver
John Shaver
Hoosier Energy Rural Electric
Cooperative, Inc.
Prairie Power, Inc.
Sunflower Electric Power
Corporation
Great River Energy
Regio
n
RFC
Segme
nts
1
SERC
1,3
SPP
1
MRO
1,3,5,6
Brazos Electric Power Cooperative, TRE
1,5
Inc.
Arizona Electric Power
WECC 4,5
Cooperative, Inc.
Southwest Transmission
WECC 1
Cooperative, Inc.
Selected Answer:
No
Answer Comment:
Certain aspects of the TPL‐001‐4 P1‐P7 events identify actions under a
steady state or a stability assessment. We have concerns that
applicable Facility Rating exceedances and BES voltages deviations, as
identified with TPL‐001‐4, are only applicable under steady state
conditions. We recommend the SDT modify Requirement R4 to identify
these references within the context of a steady state assessment,
instead of a transient state, to align with existing NERC standards.
Response: Thank you for your comment.
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136
The drafting team agrees that applicable Facility Rating and BES voltage deviations, as identified with TPL‐001‐4 are
applicable under steady‐state conditions rather than transient conditions. However, for the purpose of the
evaluation required in Requirement R4, Part 4.1.3 (Parts 4.1.3.1‐4.1.3.5), RAS inadvertent operation needs to be
assessed with regards to both the transient stability and steady‐state performance requirements of TPL‐001‐4 P1‐P7
(as for any TPL contingency). The drafting team declines to make the suggested change.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
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137
Requirement R4 mandates that the Transmission Planner perform a technical evaluation (planning analyses) of each RAS at least once
every 60 full calendar months to verify the continued effectiveness and coordination of the RAS, including BES performance following an
inadvertent operation and single component failure of the RAS. Questions 2, 3, and 4 pertain to these topics.
4. RAS Single Component Failure: Do you agree with Requirement 4 Part 4.4 and Attachment 1 which stipulates that any RAS intended
to satisfy System performance requirements in a TPL standard must still satisfy those requirements when experiencing a single
component failure? (Note that this requirement remains unchanged from PRC‐012‐0 R1.3.) If no, please provide the basis for your
disagreement and an alternate proposal.
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Selected Answer:
Yes
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Region
Joe Depoorter
Madison Gas & Electric
MRO
Amy Casucelli
Xcel Energy
MRO
Chuck Lawrence
American Transmission Company
MRO
Chuck Wicklund
Otter Tail Power Company
MRO
Segments
3,4,5,6
1,3,5,6
1
1,3,5
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138
Theresa Allard
Minnkota Power Cooperative, Inc
MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative
MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power Administration MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
MRO
1,3,5
Selected Answer:
No
Answer Comment:
The NSRF recommends two modifications to Part 4.4.:
One modification is to explicitly include “option c” in the Implementation
section of the Supplemental Material associated with the Standard. The
revised wording could be, “A single component failure in RAS, when the RAS
is intended to operate, or alternative automatic actions back up the failures
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139
of single RAS components . . .” Including text about the alternative option in
the standard, rather than the Supplemental Material would assure that it
cannot be dismissed by an auditor.
The other modification is to remove the unnecessary linking of R4.4 to TPL‐
001‐4 performance requirements with linking to the performance
requirements already expressed in R4.3 of PRC‐002‐2. The revised wording
could be, “. . . satisfies the same performance criteria given in Part 4.3”. This
change makes the performance requirements of Part 4.3 and Part 4.4
consistent with each other and subject to changes in the PRC‐012‐2, rather
than independent changes in another NERC standard.
Response: Thank you for your comments.
The drafting team maintains that the alternative automatic actions described in the Attachment 1 (Supplemental Material)
are examples of how the standard requirement can be met. The standard is not prescriptive in dictating the “how” to achieve
the reliability objectives. The language of Requirement 4, Part 4.1.4 does not preclude any of the options ‘a’ through ‘d’ from
being applied. As long as the relevant TPL standard performance requirements are satisfied, Part 4.1.4 is met. The drafting
team declines to make the suggested change.
The intent of Requirement 4, Part 4.1.4 is to ensure the RAS satisfies all of the performance requirements specified in the TPL
standard (which are more than those listed in Part 4.1.3) with regards to single component failure. Furthermore, the drafting
team contends that the reference to the TPL standard is necessary to differentiate between RAS installed for meeting
planning event performance requirements and those installed for extreme events. The drafting team declines to make the
suggested change.
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
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140
Selected Answer:
Yes
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC
Group Name:
Seattle City Light Ballot Body
Group Member Name
Entity
Region Segments
Pawel Krupa
Seattle City Light
WECC 1
Dana Wheelock
Seattle City Light
WECC 3
Hao Li
Seattle City Light
WECC 4
Bud (Charles) Freeman
Seattle City Light
WECC 6
Mike haynes
Seattle City Light
WECC 5
Michael Watkins
Seattle City Light
WECC 1,3,4
Faz Kasraie
Seattle City Light
WECC 5
John Clark
Seattle City Light
WECC 6
Selected Answer:
Yes
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141
Chris Scanlon ‐ Exelon ‐ 1 ‐
Group Name:
Group Member Name
Chris Scanlon
John Bee
Selected Answer:
Exelon Utilities
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company Holdings
Corporation, 1
Entity
Region Segments
BGE, ComEd, PECO TO's
RFC
1
BGE, ComEd, PECO LSE's
RFC
3
Yes
Selected Answer:
Yes
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Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Selected Answer:
Yes
142
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Yes
Jeri Freimuth ‐ APS ‐ Arizona Public Service Co. ‐ 3 ‐
Selected Answer:
Yes
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP
Selected Answer:
No
Answer Comment:
We do not agree that the “single component failure” requirement should
apply to all RAS installed to satisfy TPL performance requirements, by
completely disregarding the severity of adverse system impact resulting from
the RAS failure to operate. In other words, we are advocating that due regard
be given to the RAS classifications/types existing in NPCC, WECC and TRE
regions, as well as the recommended RAS/SPS classifications in the SAMS‐
SPCS white paper. Using the RAS nomenclature proposed in the white paper,
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143
we recommend that the “single component failure” requirement be limited
to Type PS (Planning Significant) schemes only. Excluding the Type PL
schemes, like the accepted exclusion for “safety net” (Type ES/EL) schemes,
does not necessarily compromise Adequate Level of Reliability in the BES. We
recognize that this approach will require judicious selection of the
demarcation criteria between Significant (Wide Area) versus Limited (Local)
schemes – however, the existing NPCC and/or WECC demarcation criteria
may serve as a reasonably good starting point. Lastly, we disagree with the
claim that Part 4.4 remains unchanged from the existing R1.3 in PRC‐012‐0 –
although both may have essentially the same verbiage, the context and the
scope of applicability are widely different. While the existing R1.3 may be
rightly interpreted to allow discretion to the RRO to determine which
RAS/SPS “Types” must be subject to the more robust design that is not
degraded by “single component failure”, Part 4.4 takes away that discretion
by virtue of being a continent‐wide standard. There is no factual evidence to
suggest that the failure‐to‐operate of any Local/Limited RAS has resulted in
unacceptable/adverse BES performance to warrant “raising the bar” on
applicability of “single component failure” requirement.
Response: Thank you for your comment.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective date of this
standard that has been through the regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in
WECC will be recognized as limited impact. When appropriate, new or functionally modified RAS implemented after the
effective date of this standard will be designated as limited impact by the Reliability Coordinator during the RAS review
process.
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Molly Devine ‐ IDACORP ‐ Idaho Power Company ‐ 1 ‐
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Response: Please see the drafting team’s responses to the referenced comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
145
Group Name:
Group Member Name
Steve Edwards
Joel Masters
David Greene
Jammie Lee
Greg Davis
Selected Answer:
Answer Comment:
David Greene ‐ SERC ‐ 1,10 ‐ SERC
SERC PCS
Entity
Region Segments
Dominion
SERC
1
SCE&G
SERC
1
SERC staff
SERC
10
MEAG
SERC
1
GTC
SERC
1
Yes
Suggest adding clarity to indicate the intent of R4 is not to evaluate the
performance of the RAS “following” an inadvertent operation since this is
covered by R5. The below statement from the rationale for R4 can be
misinterpreted to imply R4 requires the Transmission Planner to perform a
technical evaluation “following” an inadvertent operation.
Copied from Rationale for R4:
The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that
requirements for BES performance following an inadvertent RAS
operation or a single component failure in the RAS continues to be satisfied.
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Response: Thank you for your comment.
The drafting team agrees and revised the Requirement R4 rationale sentence as follows: “The purpose of a periodic RAS
evaluation is to verify the continued effectiveness and coordination of the RAS, as well as to verify that, if a RAS single
component failure or single component malfunction were to occur, requirements for BES performance would continue to be
satisfied.”
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Selected Answer:
No
Answer Comment:
ATC recommends two modifications to Part 4.4.
One modification is to explicitly include “option c” in the Implementation
section of the Supplemental Material associated with the Standard. The
revised wording could be, “A single component failure in RAS, when the RAS
is intended to operate, or alternative automatic actions back up the failures
of single RAS components . . .” Including text about the alternative option in
the standard, rather than the Supplemental Material would assure that it
cannot be dismissed by an auditor.
The other modification is to remove the unnecessary linking of R4.4 to TPL‐
001‐4 performance requirements with linking to the performance
requirements already expressed in R4.3 of PRC‐002‐2. The revised wording
could be, “. . . satisfies the same performance criteria given in Part 4.3”. This
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147
change makes the performance requirements of Part 4.3 and Part 4.4
consistent with each other and subject to changes in the PRC‐012‐2, rather
than independent changes in another NERC standard.
Response: Thank you for your comments.
The drafting team maintains that alternative automatic actions described in the Attachment 1 supplemental material are
examples of how the standard requirement can be met. The standard is not prescriptive in dictating the “how” to achieve
the reliability results. The language of Requirement 4, Part 4.4 does not preclude any of the options ‘a’ through ‘d’ from
being applied. As long as the relevant TPL standard performance requirements are satisfied, Part 4.4 is met. The drafting
team declines to make the suggested change.
The intent of Requirement 4, Part 4.4 is to ensure the RAS satisfies all of the performance requirements specified in the TPL
standard, which are more than those listed in Part 4.3, with regards to single component failure. The drafting team also
contends that the reference to the TPL standard is necessary to differentiate between RAS installed for meeting planning
event performance requirements and those installed for extreme events. The drafting team declines to make the suggested
change.
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First,
placing this requirement on the Transmission Planner does not conform to
the responsibilities or abilities of the Transmission Planner. While the TP may
have some familiarity with the design of the RAS or with the Operating
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Procedures which may be in place, it does not know or need to know the
specifics of a single component failure, just the ramification of an overall RAS
operation failure or inadvertent operation. Currently, the unapproved
standard PRC‐012‐0 and ‐1 R1.3 contains a single component failure design
requirement which is currently unapproved by FERC and the applicable
governmental authorities in Canada. When these standards were approved
by the NERC BOT there was no NERC BES definition nor was there an
approved definition of what a RAS is. We believe that had the full implication
of the costs to be borne by the industry been recognized and subsequent
minimal or no reliability benefit associated with meeting that requirement for
local impact only schemes, the standard would not have been
approved. Further, the System Protection Coordination Subcommittee of
NERC had specifically noted and suggested that 4 types of RAS are on the
BES. Two of these were local and these categories were developed to afford
the SDT to tailor specific and appropriate reliability and security requirements
on these local type schemes. To broadly apply these more stringent
requirements to all RAS on the new BES with the new RAS definition has little
cost benefit. In addition, the existing PRC‐012‐0 and ‐1 only require a single
component failure review and design requirement at the time of
review. PRC‐014‐0 and ‐1, which are the SPS/RAS assessment standards
currently do not require the Transmission Planner to include a requirement
such as Requirement R4 Part 4.4 in their periodic assessment.
The regions should each have a process for ensuring the reliability of the BES
and that the necessary level of reliability and security had been met at the
time of approval. Furthermore, misoperations studies have not indicated that
there is a reliability need to incorporate single component failure design into
local systems. These local RAS which do not meet the requirement would
need to be redesigned, outages taken and then have their revisions made to
come into compliance. This, in and of itself would represent a risk to the
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operation and reliability of the BES.
Requirement R4 Part 4.4 currently states;
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if the SDT is unwilling to remove
it we would propose the following:
4.4 A single component failure in the RAS, when the RAS is intended to
operate,
does not result in any of the following conditions on the BES:
o Cascading
o Uncontrolled System Separation
o Instability
The above modification would provide the necessary level of security and
reliability to the BES. Ensuring that RAS installed on the BES or to meet TPL
requirements would only be required when the RAS operation is critical and
any inadvertent operation results in a significant impact to the BES.
Response: Thank you for your comments.
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The drafting team revised Requirement 4 to make the Planning Coordinator (PC) the responsible entity. The drafting team
maintains that the PC does not need to know the detailed RAS design and can consult with the RAS‐entity to ascertain the
consequences of any single component failure. The drafting team maintains that the PC is the proper entity to perform the
System performance evaluations listed in Requirement 4, Parts 4.1 through 4.4. The revisions to Requirement 4, Part 4.4
have effectively limited the number of RAS to be evaluated for single component failure and the amount of associated data
the PC will need to obtain to perform the evaluation.
The drafting team agrees in principle with your comment and has revised Requirement 4, Part 4.4 to allow the Reliability
Coordinator to determine whether a RAS has a “limited impact” and can therefore be exempted from Part 4.4 of the
requirement. The drafting team also added an explanatory footnote and revised Attachments 1 and 2 to reflect the change in
Part 4.4.
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
Yes
Answer Comment:
Please affirm this understanding: For single component failure, a RAS must
still satisfy System performance requirements.
Response: Thank you for your comments.
The drafting team agrees with your comment. Please see the revised Requirement 4, Part 4.4 which no longer applies to
limited impact RAS.
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Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First,
placing this requirement on the Transmission Planner does not conform to
the responsibilities or abilities of the Transmission Planner. While the TP may
have some familiarity with the design of the RAS or with the Operating
Procedures in place, they do not know or need to know the specifics of a
single component failure. The TP just needs to know the ramifications of an
overall RAS operation failure or inadvertent operation. Currently, standards
PRC‐012‐0 and PRC‐012‐1 R1.3 contain a single component failure design
requirement. When these standards were approved by the NERC BOT, there
was no NERC BES definition nor was there an approved definition of a
RAS. We believe that had the full implication of the costs to be borne by the
industry and the subsequent minimal or no reliability benefit associated with
this (local impact only schemes) had been recognized, the standard would not
have been approved by the NERC BOT. Further, the System Protection
Coordination Subcommittee of NERC had specifically noted and suggested
that 4 types of RAS are on the BES. Two of these types were local and these
categories were developed to allow the SDT to tailor specific and appropriate
reliability and security requirements on these local type schemes. To broadly
apply these more stringent requirements to all RAS on the new BES with the
new RAS definition has no cost benefit. In addition, PRC‐012‐0 and PRC‐012‐1
only require a single component failure review and design requirement at the
time of review. PRC‐014‐0 and PRC‐014‐1, which are the SPS/RAS assessment
standards, currently do not require the Transmission Planner to include a
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
152
requirement such as Requirement R4 Part 4.4 in their periodic assessment.
The SDT has gone, in our view, unnecessarily beyond the intent of the current
standards in this regard.
In addition, it should be noted that all existing RAS have gone through
regional reviews and been approved for implementation. These existing RAS
may not have met the existing single component failure requirement due to
the revision of the BES. The regions each have a process for ensuring the
reliability of the BES and the necessary level of reliability and security has
been met at the time of approval. Furthermore, misoperations studies have
not indicated that there is a reliability need to incorporate single component
failure design into local systems. These local RAS, which do not meet the
requirement, would need to be redesigned, undergo outages, and then have
revisions made to bring them into compliance. This, in and of itself would
represent a risk to the operation and reliability of the BES.
Requirement R4 Part 4.4 currently states:
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if the SDT is unwilling to remove
it, we propose the following:
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not result in any of the following conditions on the BES:
• Cascading
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
153
• Uncontrolled System Separation
• Instability”
The above modification would provide the necessary level of security and
reliability to the BES. This ensures that RAS installed on the BES or installed to
meet TPL requirements would only be required to meet Part 4.4 when the
RAS operation is critical and any inadvertent operation results in a significant
impact to the BES.
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Response: Thank you for your comments.
Based on other comments, the drafting team revised Requirement 4 to make the Planning Coordinator (PC) the responsible
entity. The drafting team maintains that the PC does not need to know the detailed RAS design and can consult with the RAS‐
entity to ascertain the consequences of any single component failure. The drafting team maintains that the PC is the proper
entity to perform the System performance evaluations listed in Requirement 4, Parts 4.1 through 4.4. The revisions to
Requirement 4, Part 4.4 have effectively limited the number of RAS to be evaluated for single component failure and the
amount of associated data the PC will need to obtain to perform the evaluation.
The drafting team agrees in principle with your comment and has revised Requirement 4, Part 4.4 to allow the Reliability
Coordinator to determine whether a RAS has a “limited impact” and can therefore be exempted from Part 4.4 of the
requirement. The drafting team also added an explanatory footnote and revised Attachments 1 and 2 to reflect the change in
Part 4.4.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
154
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Southern Company
Entity
Region Segments
Southern Company Services, Inc.
SERC
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation and SERC
6
Energy Marketing
Yes
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Selected Answer:
Yes
155
Mike ONeil ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐
Selected Answer:
Yes
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐
Group Name:
IRC Standards Review Committee
Group Member Name
Entity
Region Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC 2
Greg Campoli
NYISO
NPCC 2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC 2
Lori Spence
MISO
MRO 2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC 2
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
156
Selected Answer:
Answer Comment:
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Selected Answer:
Answer Comment:
Response:
Yes
Yes
See comment in no. 7.
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First,
placing this requirement on the Transmission Planner does not conform to
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
157
the responsibilities or abilities of the Transmission Planner. The TP, although
may have some familiarity with the design of the RAS or with the Operating
Procedures which may be in place does not know or need to know the
specifics of a single component failure, just the ramification of an overall RAS
operation failure or inadvertent operation. Currently, the unapproved
standard PRC‐012‐0 and ‐1 R1.3 contains a single component failure design
requirement which is currently unapproved by FERC and the applicable
governmental authorities in Canada. When these standards were approved
there was no NERC BES definition nor was there an approved definition of
what a RAS is. We believe that had the full implication of the costs to be
borne by the industry been recognized and subsequent minimal or no
reliability benefit associated with meeting that requirement for local impact
only schemes, the standard would not have been approved. Further, the
System Protection Coordination Subcommittee of NERC had specifically noted
and suggested that 4 types of RAS are on the BES. Two of these were local
and these categories were developed to afford the SDT to tailor specific and
appropriate reliability and security requirements on these local type
schemes. To broadly apply these more stringent requirements to all RAS on
the new BES with the new RAS definition has no cost benefit. In addition, the
existing PRC‐012‐0 and ‐1 only require a single component failure review and
design requirement at the time of review. PRC‐014‐0 and ‐1, which are the
SPS/RAS assessment standards currently do not require the Transmission
Planner to include a requirement such as Requirement R4 Part 4.4 in their
periodic assessment. The SDT has gone, in our view, unnecessarily beyond
the intent of the current standards in this regard.
In addition it should be noted that all existing RAS have gone through regional
reviews and been approved for implementation. These existing RAS may not
have met the existing single component failure requirement due to the
revision of the BES. The regions each have a process for ensuring the
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
158
reliability of the BES and that the necessary level of reliability and security
had been met at the time of approval. Furthermore, misoperations studies
have not indicated that there is a reliability need to incorporate single
component failure design into local systems. These local RAS which do not
meet the requirement would need to be redesigned, outages taken and then
have their revisions made to come into compliance. This, in and of itself
would represent a risk to the operation and reliability of the BES.
Requirement R4 Part 4.4 currently states;
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if the SDT is unwilling to remove
it we would propose the following:
4.4 A single component failure in the RAS, when the RAS is intended to
operate,
does not result in any of the following conditions on the BES:
o Cascading
o Uncontrolled System Separation
o Instability
The above modification would provide the necessary level of security and
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
159
reliability to the BES. Ensuring that RAS installed on the BES or to meet TPL
requirements would only be required when the RAS operation is critical and
any inadvertent operation results in a significant impact to the BES.
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Response: Thank you for your comments.
The drafting team revised Requirement 4 to make the Planning Coordinator (PC) the responsible entity. The drafting team
maintains that the PC does not need to know the detailed RAS design and can consult with the RAS‐entity to ascertain the
consequences of any single component failure. The drafting team maintains that the PC is the proper entity to perform the
System performance evaluations listed in Requirement 4, Parts 4.1 through 4.4. The revisions to Requirement 4, Part 4.4
have effectively limited the number of RAS to be evaluated for single component failure and the amount of associated data
the PC will need to obtain to perform the evaluation.
The drafting team agrees in principle with your comment and has revised Requirement 4, Part 4.4 to allow the Reliability
Coordinator to determine whether a RAS has a “limited impact” and can therefore be exempted from Part 4.4 of the
requirement. The drafting team also added an explanatory footnote and revised Attachments 1 and 2 to reflect the change in
Part 4.4.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
160
Group Member Name
Entity
Region Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Selected Answer:
No
Answer Comment:
Dominion believes that redundancy should not be required for a RAS
designed for events such as TPL‐001‐4 P4 (stuck breaker) or P5 (relay failure
event). The design should not have to consider two failures which is
improbable. As an analogy, in places where there is no RAS scheme, there is
no requirement to test a P4 stuck breaker event and then assume that the
breaker failure relay does not work, essentially combining P4 and P5
together. Designing a redundant RAS for breaker failure could require
installation of two breaker failure relays per breaker to initiate the RAS and
maintain complete redundancy. This leads to excessive complexity which can
hurt reliability.
Additionally, Dominion suggest adding clarity to indicate the intent of R4 is
not to evaluate the performance of the RAS “following” an inadvertent
operation since this is covered by R5. The rationale statement for R4 can be
misinterpreted to imply R4 requires the Transmission Planner to perform a
technical evaluation “following” an inadvertent operation.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
161
Requirements R6 and R7 pertain to the development and implementation of
Corrective Action Plans (CAPs). Question 5 addresses these requirements.
Response: Thank you for your comments.
The SDT agrees that a single component failure of a RAS during a P4 or P5 event has a low probability of occurrence.
However, the SDT maintains that the single component failure requirement applies to contingencies in TPL‐003 in the
current standard. Not having the single component failure test apply to P4 or P5 events would be lowering the bar from the
previous standard.
The SDT agrees and has revised the R4 rationale sentence as follows: “The purpose of a periodic RAS evaluation is to verify
the continued effectiveness and coordination of the RAS, as well as to verify that, if a RAS single component failure or single
component malfunction were to occur, requirements for BES performance would continue to be satisfied.”
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Group Member Name
Entity
Joseph Smith
Public Service Electric and Gas
Jeffrey Mueller
Public Service Electric and Gas Co.
Tim Kucey
PSEG Fossil LLC
Karla Jara
PSEG Energy Resources & Trade LLC
Region Segments
RFC
1
RFC
3
RFC
5
RFC
6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
162
Answer Comment:
No comment
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Group Name:
FE RBB
Group Member Name
Entity
Region
William Smith
FirstenergyCorp
RFC
Cindy Stewart
FirstEnergy Corp.
RFC
Doug Hohlbaugh
Ohio Edison
RFC
Robert Loy
FirstEnergy Solutions
RFC
Richard Hoag
FirstenergyCorp
RFC
Segments
1
3
4
5
NA ‐ Not
Applicable
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
163
6
Selected Answer:
Yes
Ann Ivanc
FirstEnergy Solutions
FRCC
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Alan Adamson
New York State Reliability Council,
LLC
David Burke
Orange and Rockland Utilities Inc.
Greg Campoli
New York Independent System
Operator
Gerry Dunbar
Northeast Power Coordinating
Council
Mark Kenny
Northeast Utilities
Helen Lainis
Independent Electricity System
Operator
Rob Vance
New Brunswick Power Corporation
Paul Malozewski
Hydro One Networks Inc.
Bruce Metruck
New York Power Authority
Region Segments
NPCC 10
NPCC 3
NPCC 2
NPCC 10
NPCC 1
NPCC 2
NPCC 9
NPCC 1
NPCC 6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
164
Lee Pedowicz
David Ramkalawan
Northeast Power Coordinating
Council
Ontario Power Generation, Inc.
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
NPCC
10
NPCC
5
Silvia Parada Mitchell
Northeast Power Coordinating
Council
NextEra Energy, LLC
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
NPCC
1
Michael Forte
Brian O'Boyle
Peter Yost
Sylvain Clermont
NPCC
1
NPCC
8
NPCC
3
NPCC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
165
Si Truc Phan
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Selected Answer:
No
Answer Comment:
Requirement R4 Part 4.4 is problematic for a number of reasons. First,
placing this requirement on the Transmission Planner does not conform to
the responsibilities or abilities of the Transmission Planner. The TP may have
some familiarity with the design of the RAS or with the Operating Procedures
which may be in place, but does not know or need to know the specifics of a
single component failure, just the ramification of an overall RAS operation
failure or inadvertent operation. Currently, Part R1.3 of standards PRC‐012‐0
and ‐1 contains a single component failure design requirement. When these
standards were approved by the NERC BOT there was no NERC BES definition
nor was there an approved definition of what a RAS is. We believe that had
the full implication of the costs to be borne by the industry been recognized
and subsequent minimal or no reliability benefit associated with meeting that
requirement for local impact only schemes, the standard would not have
been approved by the NERC BOT. Furthermore, the System Protection
Coordination Subcommittee of NERC had specifically noted and suggested
that 4 types of RAS are on the BES. Two of these were local and these
categories were developed to afford the SDT to tailor specific and appropriate
reliability and security requirements on these local type schemes. To broadly
apply these more stringent requirements to all RAS on the new BES with the
new RAS definition has little cost benefit. In addition, the existing PRC‐012‐0
and ‐1 only require a single component failure review and design requirement
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
166
at the time of review. PRC‐014‐0 and ‐1, which are the SPS/RAS assessment
standards currently do not require the Transmission Planner to include a
requirement such as Requirement R4 Part 4.4 in their periodic
assessment. The SDT has gone unnecessarily beyond the intent of the current
standards in this regard.
In addition it should be noted that all existing RAS have gone through regional
reviews and been approved for implementation. These existing RAS may not
have met the existing single component failure requirement due to the
revision of the BES. The regions each have a process for ensuring the
reliability of the BES, and that the necessary level of reliability and security
had been met at the time of approval. Furthermore, misoperation studies
have not indicated that there is a reliability need to incorporate single
component failure design into local systems. These local RAS which do not
meet the requirement would need to be redesigned, outages taken, and then
revisions made to come into compliance. This, in and of itself would
represent a risk to the operation and reliability of the BES.
Requirement R4 Part 4.4 currently states;
“4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as
those required for the events and conditions for which the RAS is designed.”
We suggest Part 4.4 be removed. However, if not removed, we propose the
following:
4.4 A single component failure in the RAS, when the RAS is intended to
operate, does not result in any of the following conditions on the BES:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
167
o Cascading
o Uncontrolled System Separation
o Instability
The above modification would provide the necessary level of security and
reliability to the BES. Ensuring that RAS installed on the BES or installed to
meet TPL requirements would only be required when the RAS operation is
critical, and any inadvertent operation results in a significant impact to the
BES.
Response: Thank you for your comments.
The drafting team revised Requirement 4 to make the Planning Coordinator (PC) the responsible entity. The drafting team
maintains that the PC does not need to know the detailed RAS design and can consult with the RAS‐entity to ascertain the
consequences of any single component failure. The drafting team maintains that the PC is the proper entity to perform the
System performance evaluations listed in Requirement 4, Parts 4.1 through 4.4. The revisions to Requirement 4, Part 4.4
have effectively limited the number of RAS to be evaluated for single component failure and the amount of associated data
the PC will need to obtain to perform the evaluation.
The drafting team agrees in principle with your comment and has revised Requirement 4, Part 4.4 to allow the Reliability
Coordinator to determine whether a RAS has a “limited impact” and can therefore be exempted from Part 4.4 of the
requirement. The drafting team also added an explanatory footnote and revised Attachments 1 and 2 to reflect the change in
Part 4.4.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
168
Selected Answer:
Answer Comment:
Response:
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2 ‐
Yes
ERCOT supports the comments submitted by the ISO/RTO Council.
Mark Holman ‐ PJM Interconnection, L.L.C. ‐ 2 ‐
Selected Answer:
Yes
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Selected Answer:
No
Answer Comment:
Single component failures should exclude station dc supply and some
portions of communications systems (e.g., microwave towers and
multiplexing equipment). Such exceptions have existed in the industry.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
169
For a single component failure, it is unclear why the requirement was
changed from simply having to meet the performance requirements defined
in TPL standards to having to meet those required for the events and
conditions for which the RAS is designed.
In the Q & A document, section 5, page 4, how can arming excess load and
generation not impact reliability? TPL footnote 9 notes that “the planning
process should be to minimize the likelihood and magnitude of interruption.”
RAS entities should be allowed to consider whether a 100% chance of tripping
too much load/generation in the event of correct RAS operation really meets
the intent of TPL. In some cases, allowing a single point failure to degrade the
performance of the RAS is a better overall choice for minimizing total
probability of interruption.
In the Q & A document, section 5, page 4, what kind of automatic actions are
referenced? As the NERC reliability standards have evolved, the classification
of RAS has expanded from just very high complexity protection schemes to
now include many kinds of routine automatic actions. Almost any automatic
action used to mitigate a TPL violation would become a RAS by virtue that it is
used to meet requirements identified in a NERC Reliability Standard.
Response: Thank you for your comments.
The drafting team declines to identify RAS components that could be excluded from the single component failure aspect of
the requirement. For new and modified RAS, single component failure design will be reviewed by the RC and any
components subject to inclusion or exclusion will be determined at that time.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
170
The drafting team used the words “meet those required for the events and conditions for which the RAS is designed” to be
consistent with our understanding of the existing standard PRC‐012‐0. This also makes it clear that a RAS designed for an
extreme event does not have to meet the performance requirements listed in the TPL standard.
Arming excess load and generation in a RAS is only allowed when tripping load or generation is allowed by TPL‐001‐4. If it is
allowed by TPL‐001‐4, then it should not be affecting the reliability of the system (according to that standard). Allowing a
single component failure to degrade the performance of the RAS may minimize the total probability of interruption.
However, the RAS would have been designed and placed into service to solve some System performance issue. It is better to
ensure that the System performance issue is satisfied for single component failures even if additional load or generation has
to be armed for interruption.
Automatic actions may or may not be classified as a RAS. An example which would not be classified as a RAS would be a UVLS
Program (consisting of only distributed relays) which is located in the same area as a RAS. The RAS was separately installed to
solve a voltage problem in an area. The UVLS Program is not a RAS but the automatic action taken by the UVLS relays,
assuming that load shedding is permissible for the event under the TPL standard, could provide the necessary relief if a single
component of the RAS failed.
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Selected Answer:
No
Answer Comment:
At the present time there are RAS in service that have a limited local impact.
To universally apply the same design criteria to all RAS regardless of their
impact on BES in case of failure to operate may have no cost benefit in the
case of the RAS installed to address local problems.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
171
We propose the following to be included in the standard:
The failure of a RAS to operate does not result in any of the following
conditions on the BES:
1. Cascading
2. Uncontrolled System Separation
3. Instability
When the criteria mentioned above is not met a redundant design will be
required.
When a RAS is used to respond to an event, e.g. category P1 in TPL‐001‐4, its
failure should be considered to be a more severe event, just as in TPL‐001‐4
the failure of a breaker or protection relay following a P1 event is recognized
as “Multiple Contingency” (category P3 and P4). For this reason, the system
performance with a RAS failure should not be required to meet the same
requirements (defined in TPL‐001‐4) as those for the original event.
We suggest that the system performance requirement in case of failure of a
single component of a RAS be limited to the following:
1. The BES shall remain stable
2. Cascading or Uncontrolled System Separation shall not occur
Response: Thank you for your comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
172
The drafting team agrees in principle with your comment and has revised Requirement 4, Part 4.4 to allow the Reliability
Coordinator to determine whether a RAS has a “limited impact” and can therefore be exempted from Part 4.4 of the
requirement. The drafting team also added an explanatory footnote and revised Attachments 1 and 2 to reflect the change in
Part 4.4.
The SDT agrees that a single component failure of a RAS during a P3 or P4 event has a low probability of occurrence.
However, the SDT maintains that the single component failure requirement applies to contingencies in TPL‐003 in the
current standard. Not having the single component failure test apply to P3 or P4 events would be lowering the bar from the
previous standard.
Richard Vine ‐ California ISO ‐ 2 ‐
Selected Answer:
Yes
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards Review
Committee
Response: Please see the drafting team’s responses to the referenced comments.
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
173
Selected Answer:
Yes
LCRA Compliance
Entity
Region Segments
LCRA
TRE
6
LCRA
TRE
1
LCRA
TRE
5
Yes
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP
Group Name:
SPP Standards Review Group
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
Group Member Name
Michael Shaw
Teresa Cantwell
Dixie Wells
Selected Answer:
174
Group Member Name
Entity
Region Segments
Shannon Mickens
Southwest Power Pool Inc.
SPP
2
Jason Smith
Southwest Power Pool Inc
SPP
2
James Nail
City of Independence, Missouri
SPP
3,5
Selected Answer:
Yes
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Jeff Wells ‐ Grand River Dam Authority ‐ 3 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
Selected Answer:
Yes
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Yes
175
Selected Answer:
Yes
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Yes
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Selected Answer:
Yes
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1 ‐
Selected Answer:
No
Answer Comment:
When a RAS is used to respond to an event, e.g. category P1 in TPL‐001‐4, its
failure should be considered to be a more severe event, just as in TPL‐001‐4
the failure of a breaker or protection relay following a P1 event is recognized
as “Multiple Contingency” (category P3 and P4). For this reason, the system
performance with a RAS failure should not be required to meet the same
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176
requirements (defined in TPL‐001‐4) as those for the original event.
We suggest that the system performance requirement in case of failure of a
single component of a RAS be limited to the following:
1. The BES shall remain stable
2. Cascading or Uncontrolled System Separation shall not occur
Please also see the following comments for relaxing the requirements for a
class of RAS.
Response: Thank you for your comments.
The drafting team revised Requirement 4 to make the Planning Coordinator (PC) the responsible entity. The drafting team
maintains that the PC does not need to know the detailed RAS design and can consult with the RAS‐entity to ascertain the
consequences of any single component failure. The drafting team maintains that the PC is the proper entity to perform the
System performance evaluations listed in Requirement 4, Parts 4.1 through 4.4. The revisions to Requirement 4, Part 4.4
have effectively limited the number of RAS to be evaluated for single component failure and the amount of associated data
the PC will need to obtain to perform the evaluation.
The drafting team agrees in principle with your comment and has revised Requirement 4, Part 4.4 to allow the Reliability
Coordinator to determine whether a RAS has a “limited impact” and can therefore be exempted from Part 4.4 of the
requirement. The drafting team also added an explanatory footnote and revised Attachments 1 and 2 to reflect the change in
Part 4.4.
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
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177
Group Name:
Group Member Name
Tim Beyrle
Jim Howard
Lynne Mila
Javier Cisneros
Randy Hahn
Don Cuevas
Stan Rzad
Matt Culverhouse
Tom Reedy
Steven Lancaster
Mike Blough
Mark Brown
Mace Hunter
Selected Answer:
FMPA
Entity
Region Segments
City of New Smyrna Beach
FRCC 4
Lakeland Electric
FRCC 3
City of Clewiston
FRCC 3
Fort Pierce Utility Authority
FRCC 4
Ocala Utility Services
FRCC 3
Beaches Energy Services
FRCC 1
Keys Energy Services
FRCC 4
City of Bartow
FRCC 3
Florida Municipal Power Pool
FRCC 6
Beaches Energy Services
FRCC 3
Kissimmee Utility Authority
FRCC 5
City of Winter Park
FRCC 3
Lakeland Electric
FRCC 3
Yes
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178
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
Group Member Name
Bob Solomon
Ginger Mercier
Ellen Watkins
Michael Brytowski
Shari Heino
John Shaver
John Shaver
Selected Answer:
Answer Comment:
ACES Standards Collaborators
Entity
Region Segments
Hoosier Energy Rural Electric
RFC
1
Cooperative, Inc.
Prairie Power, Inc.
SERC
1,3
Sunflower Electric Power
SPP
1
Corporation
Great River Energy
MRO 1,3,5,6
Brazos Electric Power Cooperative, TRE
1,5
Inc.
Arizona Electric Power Cooperative, WECC 4,5
Inc.
Southwest Transmission
WECC 1
Cooperative, Inc.
No
We recommend that the SDT consolidate the numerous sub‐parts in
Requirement R4, as they are confusing to both registered entity and auditor.
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179
Response: Thank you for your comment.
The subparts of Requirement R4 are distinct components of the evaluation that must be made. The drafting team maintains
that attempting to consolidate them would reduce clarity, not improve it.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
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180
Requirements R6 and R7 pertain to the development and implementation of Corrective Action Plans (CAPs). Question 5
addresses these requirements.
5. Corrective Action Plans: Do you agree that the application of Requirements R6 and R7 would address the reliability
objectives associated with CAPs? If no, please provide the basis for your disagreement and an alternate proposal.
Selected Answer:
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Yes
Barbara Kedrowski ‐ WEC Energy Group, Inc. ‐ 3,4,5,6 ‐ RFC
Selected Answer:
No
Answer Comment:
We suggest that the RAS‐owner be removed from the Requirements,
and that only the RAS‐entity be subject to these Requirements. See
below for more comments.
Response: Thank you for your comment.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
contends that the RAS‐entity as the asset owner, is in the best position to develop the actions and timelines
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181
necessary; i.e., schedule the work and submit clearances to perform the activities required to correct the
deficiencies.
Thomas Foltz ‐ AEP ‐ 5 ‐
Selected Answer:
No
Answer Comment:
AEP believes R6 should be further revised to clarify exactly when the
“six calendar months” begins. We suggest revising it to state ”Within
six‐full‐calendar months of *the RC* being notified of a deficiency…”
Response: Thank you for your comment.
The drafting team revised the requirement.
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Regio
n
Segme
nts
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182
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company
MRO
1
Chuck Wicklund
Otter Tail Power Company
MRO
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc
MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative
MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
MRO
1,6
MRO
4
Larry Heckert
Western Area Power
Administration
Alliant Energy
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
MRO
1,3,5
Selected Answer:
No
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183
Answer Comment:
The NSRF recommends revising R6 to explicitly include the Planning
Coordinator with working like, “. . . submit the CAP to its reviewing
Reliability Coordinator and impacted Transmission Planners and
Planning Coordinators”. The inclusion of Transmission Planners and
Planning Coordinators is appropriate because these entities will
generally have the best planning horizon information and expertise to
review the CAP.
Response: Thank you for your comment.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. When a deficiency is identified, the Reliability
Coordinator should make the decision whether or not to allow the RAS to remain in‐service until the Corrective
Action Plan is completed. As the drafting team has noted in responses to other comments, the RC has the “flexibility”
to request information or assistance from relevant entities (third parties) to participate in the reviews if they believe
it will enhance the quality and efficiency of the review process. This flexibility allows the RC to garner input from any
impacted Transmission Planners and Planning Coordinators.
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
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184
There appears to be a gap between R6 and R7, from the point where
each RAS owner submits a CAP to its RC, and then implementing the
CAP. There should be a requirement placed upon the RC where a review
of the CAP is completed and feedback provided to the RAS owner.
Response: Thank you for your comment.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. When a deficiency is identified and a CAP is created,
unless the CAP can be completed the same day, the Reliability Coordinator will most likely impose operating
restrictions to ensure reliability until the RAS deficiency is resolved. The drafting team contends the RAS‐entity will
work closely with the RC to expedite the return to service date of the RAS. The drafting team asserts because the RC
and RAS‐entity have a mutual interest in returning the RAS to service as soon as possible to promote the reliability of
the BES, their motivation and collaboration on this effort is sufficient, and does not necessitate the need for an
additional requirement in the standard.
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC
Answer Comment:
Group Name:
Seattle City Light Ballot Body
Group Member Name
Entity
Regio
n
Pawel Krupa
Seattle City Light
WECC
Dana Wheelock
Seattle City Light
WECC
Segme
nts
1
3
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185
Hao Li
Seattle City Light
WECC 4
Bud (Charles) Freeman
Seattle City Light
WECC 6
Mike haynes
Seattle City Light
WECC 5
Michael Watkins
Seattle City Light
WECC 1,3,4
Faz Kasraie
Seattle City Light
WECC 5
John Clark
Seattle City Light
WECC 6
Selected Answer:
No
Answer Comment:
The requirement R7 is very ambiguous about the time‐frame for
implementing a corrective action plan. Who approves the proposed
schedule?
Response: Thank you for your comments.
Each CAP is unique and consequently the implementation and completion of each CAP will be unique as well. The
RAS‐entity submits the CAP to the reviewing RC. Although RC “approval” isn’t mandated in a requirement, the RAS‐
entity must update the CAP if actions or timetables change, and communicate with the RC throughout CAP
implementation and completion.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. When a deficiency is identified and a CAP is created,
unless the CAP can be completed the same day, the Reliability Coordinator will most likely impose operating
restrictions to ensure reliability until the RAS deficiency is resolved. The drafting team contends the RAS‐entity will
work closely with the RC to expedite the return to service date of the RAS. The drafting team asserts because the RC
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186
and RAS‐entity have a mutual interest in returning the RAS to service as soon as possible to promote the reliability of
the BES, their motivation and collaboration on this effort is sufficient, and does not necessitate the need for an
additional requirement in the standard.
Chris Scanlon ‐ Exelon ‐ 1 ‐
Group Name:
Group Member Name
Chris Scanlon
John Bee
Selected Answer:
Exelon Utilities
Entity
Regio
n
BGE, ComEd, PECO TO's
RFC
Segme
nts
1
3
BGE, ComEd, PECO LSE's
RFC
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Selected Answer:
No
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187
R6 and R7 should specify a CAP is created only if deficiency is on the
RAS‐owners part of the RAS. As written, all RAS‐owners would be
responsible for submitting CAPs if a single deficiency was identified on
just one part of the RAS. As written, a RAS‐owner would be responsible
for writing a CAP and implementing the CAP for something they may
have no control over, if the deficiency is on another RAS‐owners part of
the RAS.
Response: Thank you for your comments.
If there are no deficiencies found, then it is not necessary to develop a CAP. The definition of a Corrective Action Plan
(CAP) in the Glossary of Terms Used in NERC Reliability Standards is: A list of actions and an associated timetable for
implementation to remedy a specific problem. The drafting team wrote Requirement R6 such that each RAS‐entity
shall participate in developing a CAP. This collaboration will promote awareness of RAS degradation and the efforts
and timetables to return the RAS to service. Measure M6 states that acceptable evidence may include, but is not
limited to, a dated CAP and dated communications among each RAS‐entity and each reviewing Reliability
Coordinator. Therefore, if a RAS‐entity does not own the RAS component that is deficient, it can show evidence of
participation through emails with the other RAS‐entities.
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Answer Comment:
Selected Answer:
Yes
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
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188
Selected Answer:
Yes
Yes
Molly Devine ‐ IDACORP ‐ Idaho Power Company ‐ 1 ‐
Selected Answer:
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP
Selected Answer:
Jeri Freimuth ‐ APS ‐ Arizona Public Service Co. ‐ 3 ‐
Selected Answer:
Yes
Yes
Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
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189
Selected Answer:
Yes
Answer Comment:
Although the Corrective Action Plan (CAP) does address the reliability
objectives it is unclear on the responsibilities of the parties involved. As
the requirement is written, the Owner must submit the corrective
action plan. There is a little confusion on any RAS that have multiple
owners. Would ALL the owners need to submit a CAP or only the owner
of the equipment in question? SRP recomends clarifying and possibly
designating operator as the one to submit the CAP.
Response: Thank you for your comments.
If there are no deficiencies found, then it is not necessary to develop a CAP. The definition of a Corrective Action Plan
(CAP) in the Glossary of Terms Used in NERC Reliability Standards is: A list of actions and an associated timetable for
implementation to remedy a specific problem. The drafting team wrote Requirement R6 such that each RAS‐entity
shall participate in developing a CAP. This collaboration will promote awareness of RAS degradation and the efforts
and timetables to return the RAS to service. Measure M6 states that acceptable evidence may include, but is not
limited to, a dated CAP and dated communications among each RAS‐entity and each reviewing Reliability
Coordinator. Therefore, if a RAS‐entity does not own the RAS component that is deficient, it can show evidence of
participation through emails with the other RAS‐entities.
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
No
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Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Response: Please see the drafting team’s responses to the referenced comments.
David Greene ‐ SERC ‐ 1,10 ‐ SERC
Group Name:
Group Member Name
Steve Edwards
Joel Masters
David Greene
Jammie Lee
Greg Davis
Selected Answer:
SERC PCS
Entity
Regio
n
Dominion
SERC
Segme
nts
1
SCE&G
SERC
1
SERC staff
SERC
10
MEAG
SERC
1
GTC
SERC
1
Yes
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Bob Thomas ‐ Illinois Municipal Electric Agency ‐ 4 ‐
Selected Answer:
Yes
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Selected Answer:
No
Answer Comment:
ATC recommends revising R6 to explicitly include the Planning
Coordinator with working like, “. . . submit the CAP to its reviewing
Reliability Coordinator and any applicable Planning Coordinators”. The
inclusion of Planning Coordinators is appropriate because Planning
Coordinators will generally have the best information and expertise to
review the CAP.
Response: Thank you for your comment.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. When a deficiency is identified, the Reliability
Coordinator should make the decision whether or not to allow the RAS to remain in‐service until the Corrective
Action Plan is completed. As the drafting team has noted in responses to other comments, the RC has the “flexibility”
to request information or assistance from relevant entities (third parties) to participate in the reviews if they believe
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192
it will enhance the quality and efficiency of the review process. This flexibility allows the RC to garner input from any
impacted Transmission Planners and Planning Coordinators.
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
No
Answer Comment:
Requirement R6 reads as follows:
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS‐owner
and only states they shall participate. Standard requirements need to
be specific on who is responsible for what, and when. We also suggest
that any CAP being submitted to the PC (we feel that the PC is
appropriate as discussed in comments on R1) be a “mutually agreed
upon” CAP. To address this issue we suggest the following:
Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to
Requirement R4 or Requirement R5, each RAS‐owner shall develop a
mutually agreed upon
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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193
Corrective Action Plan (CAP) with all affected Reliability Coordinators
and submit the CAP to its reviewing Planning Coordinator(s).
We suggest that the full responsibility of the development of the CAP
rest with the RAS‐entity. The rationale box states this but it needs to be
clear in the requirement. Irrespective of complexity, the need to
collaborate with others and hire consulting services, the responsibility
should rest solely on the RAS‐owner.
Also there may be a need for an additional requirement to notify the PC
and TOP when the CAP has been completed, and the RAS is performing
correctly. We will leave this for consideration by the SDT and believe
this brings specific closure to any RAS deficiency.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
Standard utility practice as well as other NERC Reliability Standards ensure the TOP and PC will be aware of the CAP
completion.
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Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
No
Answer Comment:
As mentioned in our previous comments, Peak recognizes that the RC or
TOP may impose operating restrictions to ensure reliability until the
RAS deficiency is resolved but maintains that the CAP should be
reviewed by an independent party to assure that it addresses the
reliability issues in a reasonable timeframe. . For example, a CAP could
be created with an unreasonable timeframe that unnecessarily extends
a reliability issue. This independent review by the RC and subsequent
required action by the RAS‐entity exists for new RAS but not for CAPs,
which appears inconsistent with the intent of the Standard. A process
similar to that described in R2 and R3 should also apply to CAPs and not
just new and functionally modified RAS.
Response: Thank you for your comment.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. When a deficiency is identified, the Reliability
Coordinator should make the decision whether or not to allow the RAS to remain in‐service until the Corrective
Action Plan is completed. As the drafting team has noted in responses to other comments, the RC has the “flexibility”
to request information or assistance from relevant entities (third parties) to participate in the reviews if they believe
it will enhance the quality and efficiency of the review process. This flexibility allows the RC to garner input from any
impacted Transmission Planners and/or Planning Coordinators.
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Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Selected Answer:
No
Answer Comment:
We suggest the following rewording:
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
shall develope a Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s).”
R6 should reflect that it is either solely the RAS owner’s responsibility or
both the RC and RAS owner must have responsibility and “participate”
in developing the CAP together. If the CAP requires mutual participation
to develop, then both parties (the RAS owner AND the RC) must have
compliance responsibility.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
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component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Southern Company
Entity
Regio
n
Southern Company Services, Inc.
SERC
Segme
nts
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation
and Energy Marketing
SERC
6
Yes
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Selected Answer:
Yes
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197
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Selected Answer:
No
Answer Comment:
Reclamation suggests that the RAS‐entity should be responsible for the
Corrective Action Plans (CAPs) called for in requirements R6 and
R7. Each RAS‐owner should not be responsible for developing CAPs and
coordinating them with the Reliability Coordinator (RC) because this
could result in duplication of efforts or inconsistent corrective
actions. As outlined in the Technical Justifications, “[t]he purpose of the
RAS‐entity is to be the single information conduit with each reviewing
Reliability Coordinator (RC) for all RAS‐owners for each RAS.” When
there are several owners involved in a RAS, the RC should communicate
with the RAS‐entity as one point of contact to ensure that an overall
CAP addresses any RAS deficiencies.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
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component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
Mike ONeil ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐
Selected Answer:
Yes
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐
Group Name:
IRC Standards Review Committee
Group Member Name
Entity
Regio
n
Charles Yeung
SPP
SPP
Ben Li
IESO
NPCC
Greg Campoli
NYISO
NPCC
Mark Holman
PJM
RFC
Matt Goldberg
ISONE
NPCC
Lori Spence
MISO
MRO
Christina Bigelow
ERCOT
TRE
Segme
nts
2
2
2
2
2
2
2
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199
Ali Miremadi
CAISO
WECC 2
Selected Answer:
No
Answer Comment:
The SRC agrees that the RAS entity should develop Corrective Action
Plans to evaluate RASs to address issues and/or deficiencies identified
by their evaluations, but would suggest that such entities be required to
provide the Corrective Action Plans to their Reliability Coordinator and
Planning Coordinator for review.
Response: Thank you for your comment.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. When a deficiency is identified, the Reliability
Coordinator should make the decision whether or not to allow the RAS to remain in‐service until the Corrective
Action Plan is completed. As the drafting team has noted in responses to other comments, the RC has the “flexibility”
to request information or assistance from relevant entities (third parties) to participate in the reviews if they believe
it will enhance the quality and efficiency of the review process. This flexibility allows the RC to garner input from any
impacted Transmission Planners and Planning Coordinators. The drafting team declines to make the suggested
change.
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Selected Answer:
Yes
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200
Answer Comment:
See comment in no. 7.
Response: Please see the drafting team’s responses to the referenced comment.
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Selected Answer:
No
Answer Comment:
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS‐owner
and only states they shall participate. Standard requirements need to
be specific on who is responsible for what, and when. We also suggest
that any CAP being submitted to the RC be a “mutually agreed upon”
CAP. To address this issue we suggest the following:
Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
shall develop a mutually agreed upon Corrective Action Plan (CAP) with
all affected Reliability Coordinators and submit the CAP to its reviewing
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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201
Reliability Coordinator(s).
We suggest that the full responsibility of the development of the CAP
rest with the RAS‐owner. The rationale box states this but it needs to
be clear in the requirement. Irrespective of complexity, the need to
collaborate with others and hire consulting services, the responsibility
should rest solely on the RAS‐owner.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio
n
Segme
nts
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202
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Selected Answer:
Yes
Answer Comment:
Attachment 1, Section III‐Implementation states, “5. Documentation
describing the functional testing process.” Dominion recommends
deleting this bullet. This information is not necessarily available during
the preliminary design phase. The approval of the design is sought prior
to detailed engineering. (Planning)
In R5 it states that the RAS owner analyzes the event, but in flow chart
it states RAS owner and TP. Dominion suggests that the content in the
Flow Chart be consistent with language of the Requirement.
R5 references the timeframe “within 120 calendar days”, however in
other areas of the document the time frame is stated to be “within XX
calendar months”. Dominion suggests updating the document to
reflect the actual timeframe. Dominion also believes clarification is
needed to establish “full calendar months” versus “months”.
Response: Thank you for your comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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203
The drafting team maintains that sufficient information must be provided to the RC to allow a proper review
including information describing the RAS‐entity’s plan for periodic testing. The drafting team declines to make the
suggested change.
The drafting team made the change to the flowchart.
The drafting team modeled the requirement after the requirements of PRC‐004. The drafting team maintains that
the time increment of ‘days’ rather than ‘months’ is preferable for this requirement and declines to make the
suggested change.
The drafting team uses the clarifier ‘full’ to be clear that partial time increments are not counted. For example, for
four calendar months, if the starting point is in the middle of a calendar month (October 15), four full calendar
months would begin November 1 and continue through February 28 (the last day of the month of the stated period).
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Group Member Name
Entity
Joseph Smith
Public Service Electric and Gas
Jeffrey Mueller
Public Service Electric and Gas Co.
Tim Kucey
PSEG Fossil LLC
Karla Jara
PSEG Energy Resources & Trade
LLC
Regio
n
RFC
Segme
nts
1
RFC
3
RFC
5
RFC
6
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204
Selected Answer:
No
Answer Comment:
See the comments in #2, which is critical to R6. Furthermore, the team
should modify the R6 phrase as shown below:
“…each RAS‐owner shall participate in developing a Corrective Action
Plan with the RAS‐entity which shall and submit the CAP to its reviewing
Reliability Coordinator….”
This will result in one RAS‐entity submitted CAP to the reviewing RC.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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205
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Group Name:
Group Member Name
William Smith
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Selected Answer:
FE RBB
Entity
Regio
n
FirstenergyCorp
RFC
Segme
nts
1
FirstEnergy Corp.
RFC
3
Ohio Edison
RFC
4
FirstEnergy Solutions
RFC
5
FirstenergyCorp
RFC
NA
FirstEnergy Solutions
FRCC
6
Yes
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
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206
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Alan Adamson
New York State Reliability Council,
LLC
David Burke
Orange and Rockland Utilities Inc.
Greg Campoli
New York Independent System
Operator
Gerry Dunbar
Northeast Power Coordinating
Council
Mark Kenny
Northeast Utilities
Helen Lainis
Independent Electricity System
Operator
Rob Vance
New Brunswick Power Corporation
Paul Malozewski
Hydro One Networks Inc.
Bruce Metruck
New York Power Authority
Lee Pedowicz
Northeast Power Coordinating
Council
David Ramkalawan
Ontario Power Generation, Inc.
Brian Robinson
Utility Services
Wayne Sipperly
New York Power Authority
Edward Bedder
Orange and Rockland Utilities Inc.
Regio
n
NPCC
Segme
nts
10
NPCC
3
NPCC
2
NPCC
10
NPCC
1
NPCC
2
NPCC
9
NPCC
1
NPCC
6
NPCC
10
NPCC
5
NPCC
8
NPCC
5
NPCC
1
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207
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
Silvia Parada Mitchell
Northeast Power Coordinating
Council
NextEra Energy, LLC
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
NPCC
1
NPCC
1
Sylvain Clermont
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
Si Truc Phan
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Michael Forte
Brian O'Boyle
Peter Yost
NPCC
1
NPCC
8
NPCC
3
Selected Answer:
No
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208
Answer Comment:
Requirement R6 reads as follows:
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS‐owner
and only states they shall participate. Standard requirements need to
be specific on who is responsible for what, and when. We also suggest
that any CAP being submitted to the RC be a “mutually agreed upon”
CAP. To address this issue we suggest the following:
Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
and affected Reliability Coordinator(s) shall develop a mutually agreed
upon Corrective Action Plan (CAP) and submit the CAP to its reviewing
Reliability Coordinator(s).
Also, there may be a need for an additional requirement to notify the
RC and TOP when the CAP has been completed, and the RAS is
performing correctly. This should be considered by the SDT. This brings
specific closure to any RAS deficiency.
Requirement R5 stipulates that the RAS‐owner identifies deficiencies to
its reviewing RC. Suggest R6 be revised to read:
“Within six‐full‐calendar months of identifying or of being notified of
a…”
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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209
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
The drafting team revised Requirement R7 to include the notification of each reviewing Reliability Coordinator if CAP
actions or timetables change and when the CAP is completed.
The drafting team revised Requirement R6.
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2 ‐
Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the ISO/RTO Council.
Response: Please see the drafting team’s responses to the referenced comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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210
Yes
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Selected Answer:
Mark Holman ‐ PJM Interconnection, L.L.C. ‐ 2 ‐
Selected Answer:
Yes
Eric Olson ‐ Transmission Agency of Northern California ‐ 1 ‐
Selected Answer:
No
Answer Comment:
TANC has concerns with the current language in R5, R6, and R7,
because it appears these requirements would assign the same or similar
responsibilities to “each RAS‐owner” when a single RAS operates or fails
to operate as expected. In circumstances where a single RAS has
multiple RAS‐owners, the current language would potentially create
overlapping responsibilities to analyze the RAS performance and
develop/implement a Corrective Action Plan. It seems that these
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
211
responsibilities established in R5, R6, and R7 would be more
appropriately assigned to the single RAS‐entity for a RAS rather than to
each RAS‐owner.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Requirements R5 and R6 do require each RAS‐entity to
perform the actions associated with the requirements. The drafting team maintains this will promote reliability and
that entities will not duplicate efforts. Each entity is responsible only for its RAS components. The drafting team is
confident that entities will communicate with each other if there is any question or doubt of responsibility. The
drafting team declines to make the suggested change.
The drafting team revised Requirement R7 to include the notification of each reviewing Reliability Coordinator if CAP
actions or timetables change and when the CAP is completed.
The drafting team revised Requirement R6.
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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212
Answer Comment:
Requirement R6 reads as follows:
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to
Requirement R4 or Requirement R5, each RAS‐owner shall participate in
developing a
Corrective Action Plan (CAP) and submit the CAP to its reviewing
Reliability
Coordinator(s).”
As written, R6 doesn’t clearly assign the responsibility to the RAS‐owner
and only states they shall participate. Standard requirements need to
be specific on who is responsible for what, and when. We also suggest
that any CAP being submitted to the RC be a “mutually agreed upon”
CAP. To address this issue we suggest the following:
Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to
Requirement R4 or Requirement R5, each RAS‐owner shall develop a
mutually agreed upon
Corrective Action Plan (CAP) with all affected Reliability Coordinators
and submit the CAP to its reviewing Reliability Coordinator(s).
We suggest that the full responsibility of the development of the CAP
rest with the RAS‐owner. The rationale box states this but it needs to
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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213
be clear in the requirement. Irrespective of complexity, the need to
collaborate with others and hire consulting services, the responsibility
should rest solely on the RAS‐owner.
Requirement R6 states, “Within six‐full‐calendar months of being
notified of a deficiency in its RAS pursuant to Requirement R4 or
Requirement R5…”, however, a notification does not come out of R5
since the applicability to both R5 and R6 is with the RAS owner.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
The drafting team revised Requirement R6.
Richard Vine ‐ California ISO ‐ 2 ‐
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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214
Answer Comment:
Response: Please see the drafting team’s responses to the referenced comments.
Yes
Andrew Gallo ‐ Austin Energy ‐ 6 ‐
Selected Answer:
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Selected Answer:
The California ISO supports the comments of the ISO/RTO Standards
Review Committee
Yes
Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
LCRA Compliance
Group Member Name
Entity
Regio
n
Segme
nts
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215
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Selected Answer:
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP
Group Name:
Group Member Name
Shannon Mickens
Jason Smith
James Nail
Selected Answer:
Yes
SPP Standards Review Group
Entity
Regio
n
Southwest Power Pool Inc.
SPP
Segme
nts
2
Southwest Power Pool Inc
SPP
2
City of Independence, Missouri
SPP
3,5
Yes
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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216
Selected Answer:
Yes
Jeff Wells ‐ Grand River Dam Authority ‐ 3 ‐
Selected Answer:
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Selected Answer:
Yes
Yes
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Selected Answer:
No
Answer Comment:
Texas RE is concerned there could be an extended time frame where a
RAS with a known deficiency will be in service since the requirement to
develop a Corrective Action Plan (CAP) is do so within six months. Texas
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
217
RE is also concerned there is no defined time frame for implementing
the CAP.
Response: Thank you for your comments.
The drafting team disagrees that there is a reliability risk during the time interval associated with the CAP
development though completion of the CAP because the Reliability Coordinator will require the RAS‐entity to modify
operating procedures, System configuration, generation dispatch, or employ other methods to alleviate the deficient
RAS. The RAS review associated with new or functionally modified RAS is a more comprehensive review that entail
the design, operations, and testing of the RAS.
The definition of a Corrective Action Plan (CAP) in the Glossary of Terms Used in NERC Reliability Standards is: A list
of actions and an associated timetable for implementation to remedy a specific problem. Each CAP is unique and
consequently the implementation and completion of each CAP will be unique as well. The RAS‐entity submits the
CAP to the reviewing RC. Although RC “approval” isn’t mandated in a requirement, the RAS‐entity must update the
CAP if actions or timetables change, and communicate with the RC throughout CAP implementation and completion.
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Answer Comment:
Response: Thank you for your comment.
No
The RC needs to be given the authority to reject the CAP, or suggest
changes to the CAP.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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218
The RAS‐entity must submit the CAP and other Attachment 1 information to the RC if functional modifications to the
RAS are proposed. Accordingly, pursuant to Requirement R3, the RAS‐entity must obtain approval of the RAS from
each reviewing Reliability Coordinator.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1 ‐
Selected Answer:
No
Answer Comment:
Hydro One Networks Inc. believes that as quoted below, R6 does not
clearly assign the responsibility to the RAS‐owner and only states that
they “shall participate”.
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirement R4 or Requirement R5, each RAS‐owner
shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s).”
Standard requirements need to be specific on as to who is responsible
for what, and when. We also suggest that any CAP being submitted to
the RC be a “mutually agreed upon” CAP. To address these issues, we
suggest revising the wording to read the following:
“Within six‐full‐calendar months of being notified of a deficiency in its
RAS pursuant to Requirements R4 and R5 state that each RAS‐owner
shall develop with all affected RCs, a mutually agreed upon Corrective
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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219
Action Plan (CAP) and submit the CAP to its reviewing Reliability
Coordinator(s)”. However, Hydro One Networks Inc. suggests that the
full responsibility of the development of the CAP rest with the RAS‐
owner. The rationale box states that the full responsibility of the
development of the CAP rests with the RAS‐owner, but this needs to be
clear, and explicitly stated in the requirement as well. Irrespective of
complexity, the need to collaborate with others, hire consulting
services, etc., the responsibility should rest solely on the RAS‐owner.
Requirement R6 states, “Within six‐full‐calendar months of being
notified of a deficiency in its RAS pursuant to Requirement R4 or
Requirement R5…”, however, Hydro One would like to point out that a
notification does not result from requirement R5 since the applicability
to both R5 and R6 is with the RAS owner themselves.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities. The
drafting team declines to make the suggested change.
The drafting team revised Requirement R6.
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220
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
Group Name:
FMPA
Group Member Name
Entity
Regio
n
Tim Beyrle
City of New Smyrna Beach
FRCC
Jim Howard
Lakeland Electric
FRCC
Lynne Mila
City of Clewiston
FRCC
Javier Cisneros
Fort Pierce Utility Authority
FRCC
Randy Hahn
Ocala Utility Services
FRCC
Don Cuevas
Beaches Energy Services
FRCC
Stan Rzad
Keys Energy Services
FRCC
Matt Culverhouse
City of Bartow
FRCC
Tom Reedy
Florida Municipal Power Pool
FRCC
Steven Lancaster
Beaches Energy Services
FRCC
Mike Blough
Kissimmee Utility Authority
FRCC
Mark Brown
City of Winter Park
FRCC
Mace Hunter
Lakeland Electric
FRCC
Segme
nts
4
3
3
4
3
1
4
3
6
3
5
3
3
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221
Selected Answer:
No
Answer Comment:
The RAS‐entity should be included in Requirements R6 and R7 in a
coordinating role between the RAS‐owners and the TP and/or RC. It
should be made clear that the RAS‐owners are only responsible for their
portion of the RAS.
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. The drafting team
wrote Requirement R6 such that each RAS‐entity shall participate in developing a CAP. This collaboration will
promote awareness of RAS degradation and the efforts and timetables to return the RAS to service. Measure M6
states that acceptable evidence may include, but is not limited to, a dated CAP and dated communications among
each RAS‐entity and each reviewing Reliability Coordinator. Therefore, if a RAS‐entity does not own the RAS
component that is deficient, it can show evidence of participation through emails with the other RAS‐entities.
Requirement R7 mandates each RAS‐entity to implement its portion of the RAS.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
ACES Standards Collaborators
Group Member Name
Entity
Regio
n
Segme
nts
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222
Bob Solomon
Ginger Mercier
Ellen Watkins
Michael Brytowski
Shari Heino
John Shaver
John Shaver
Hoosier Energy Rural Electric
Cooperative, Inc.
Prairie Power, Inc.
RFC
1
SERC
1,3
Sunflower Electric Power
Corporation
Great River Energy
SPP
1
MRO
1,3,5,6
Brazos Electric Power Cooperative, TRE
1,5
Inc.
Arizona Electric Power
WECC 4,5
Cooperative, Inc.
Southwest Transmission
WECC 1
Cooperative, Inc.
Selected Answer:
No
Answer Comment:
We disagree with the SDT that there needs to be two requirements to
cover CAPs. These requirements should be consolidated and simplified
to avoid unnecessary confusion and potential compliance
impacts. Furthermore, CAPs are administrative in nature and we
recommend removing these requirements under Paragraph 81
Administrative criteria.
Response: Thank you for your comments.
The drafting team maintains there are separate and distinct reliability objectives associated with the two
requirements that reference CAPs and declines to combine them.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
223
The drafting team disagrees that CAPs are administrative in nature, no changes made.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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224
6. Implementation Plan: Do you agree with the Implementation Plan? If no, please provide the basis for your disagreement and
an alternate proposal.
Selected Answer:
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Yes
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Amy Casucelli
Xcel Energy
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Theresa Allard
Minnkota Power Cooperative, Inc
Dave Rudolph
Basin Electric Power Cooperative
Kayleigh Wilkerson
Lincoln Electric System
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1,3,5,6
MRO
1
MRO
1,3,5
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,3,5,6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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225
Jodi Jenson
Larry Heckert
Western Area Power
Administration
Alliant Energy
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
Selected Answer:
MRO
1,6
MRO
4
MRO
1,3,5
Yes
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
226
Chris Scanlon ‐ Exelon ‐ 1 ‐
Group Name:
Group Member Name
Chris Scanlon
John Bee
Selected Answer:
Exelon Utilities
Entity
Regio
n
BGE, ComEd, PECO TO's
RFC
Segme
nts
1
3
BGE, ComEd, PECO LSE's
RFC
Yes
Yes
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Selected Answer:
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Selected Answer:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
227
Yes
Molly Devine ‐ IDACORP ‐ Idaho Power Company ‐ 1 ‐
Selected Answer:
Yes
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP
Selected Answer:
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Yes
Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
228
Answer Comment:
SRP notices possible confusion on the implementation for R4 and
R8. The rationale for R4 and R8 state that the 60 month time period
begins on the effective date of the standard. However, the
implementation plan does not state that similarly. There is potential
confusion for this as many entities are likely to attempt to have their
evaluations and functional tests completed by the effective date.
Response: Thank you for your comment.
The 60 full calendar month interval in Requirement R4 and the six calendar year interval in Requirement R8 both
begin on the effective date of PRC‐012‐2. The initial performance of those requirements must be completed within
the specified interval after the effective date of PRC‐012‐2. The drafting team added language to the Implementation
Plan to provide additional clarity.
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
No
Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Response: Please see the drafting team’s responses to the referenced comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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229
David Greene ‐ SERC ‐ 1,10 ‐ SERC
Group Name:
Group Member Name
Steve Edwards
Joel Masters
David Greene
Jammie Lee
Greg Davis
Selected Answer:
SERC PCS
Entity
Regio
n
Dominion
SERC
Segme
nts
1
SCE&G
SERC
1
SERC staff
SERC
10
MEAG
SERC
1
GTC
SERC
1
Yes
Bob Thomas ‐ Illinois Municipal Electric Agency ‐ 4 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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230
Selected Answer:
Yes
Yes
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
Yes
Answer Comment:
Peak interprets the Implementation Plan as grandfathering in all
existing RAS, which means review and approval of existing RAS is not
required – only for new or modified RAS. The revised Standard does not
address existing RAS, and therefore neglects any potential reliability
issues associated with them. Peak seeks clarity on this issue.
Response: Thank you for your comment.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
231
The standard addresses all RAS. Requirements R1, R2, and R3 address new or functionally modified RAS.
Requirements R4, R5, and R8 pertain to all RAS. Existing RAS are not grandfathered; however, they would not need
to go through the new RAS‐review process (Requirements R1, R2, and R3) until such time that a functional
modification was required due to an issue identified via Requirements R4, R5, or R8. The functional modification
would be described and submitted to the reviewers via a Corrective Action Plan (CAP) in conjunction with
Requirement R6.
Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Selected Answer:
Yes
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Southern Company
Group Member Name
Entity
Region
Robert A. Schaffeld
Southern Company Services, Inc.
SERC
R. Scott Moore
Alabama Power Company
SERC
William D. Shultz
Southern Company Generation
SERC
John J. Ciza
Southern Company Generation
SERC
and Energy Marketing
Segments
1
3
5
6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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232
Selected Answer:
Yes
Yes
Mike ONeil ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐
Selected Answer:
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Selected Answer:
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Selected Answer:
Yes
Yes
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
233
Selected Answer:
Yes
Answer Comment:
See comment in no. 7.
Response: Please see the drafting team’s responses to the referenced comment.
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Selected Answer:
No
Answer Comment:
The Implementation Plan should be modified to include clarification for
implementation of R4. TFSP suggests adding the language used in the
Rationale box for R4, which says: “Sixty‐full‐calendar months, which
begins on the effective date of the standard pursuant to the
implementation plan…”
The standard or the Implementation Plan should allow the RAS‐owner
sufficient time to mitigate a design deficiency identified as part of R4,
such as the lack of redundancy without removing the RAS from
service. Clarification should be provided to allow for continued
operation of an existing RAS after a single component failure scenario is
identified until a Corrective Action Plan can be completed.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
234
Response: Thank you for your comments.
The 60 full calendar month interval in Requirement R4 begins on the effective date of PRC‐012‐2. The initial
performance of the requirement must be completed within the specified interval after the effective date of PRC‐012‐2.
The drafting team added language to the Implementation Plan to provide additional clarity.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of the
Bulk Electric System within its Reliability Coordinator Area. If a design deficiency is identified as part of the Requirement
R4 planning evaluation, the Planning Coordinator in conjunction with the Reliability Coordinator should make the
decision whether or not to allow the RAS to remain in‐service until the Corrective Action Plan is completed.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Larry Nash
Dominion Virginia Power
Louis Slade
Dominion Resources, Inc.
Connie Lowe
Dominion Resources, Inc.
Randi Heise
Dominion Resources, Inc,
Regio
n
SERC
Segme
nts
1
SERC
6
RFC
3
NPCC
5
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235
Selected Answer:
Yes
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
Group Member Name
Joseph Smith
Jeffrey Mueller
Tim Kucey
Karla Jara
Selected Answer:
Answer Comment:
PSEG
Entity
Regio
n
Public Service Electric and Gas
RFC
Segme
nts
1
Public Service Electric and Gas Co.
RFC
3
PSEG Fossil LLC
RFC
5
PSEG Energy Resources & Trade
LLC
RFC
6
No
The effective date in Implementation Plan should be increased from 12
month to 36 months after the first day of the first calendar quarter after
the date the standard is approved. This reason for this delay is that
standard establishes a new working framework between RAS‐owners,
RAS‐entities, TPs, and RCs. That itself will involve considerable start‐up
effort. In return for this added delay, the first periodic review of each
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
236
RAS under R4 could be due within 36 months, with subsequent reviews
every 60 months.
Response: Thank you for your comment.
The drafting team lengthened the implementation period of the standard to thirty‐six months to provide entities
adequate time to establish the new working frameworks.
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Group Name:
FE RBB
Group Member Name
Entity
Regio
n
William Smith
FirstenergyCorp
RFC
Cindy Stewart
FirstEnergy Corp.
RFC
Segme
nts
1
3
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237
Doug Hohlbaugh
Ohio Edison
RFC
4
Robert Loy
FirstEnergy Solutions
RFC
5
Richard Hoag
FirstenergyCorp
RFC
NA ‐
Not
Applica
ble
6
Ann Ivanc
Selected Answer:
FirstEnergy Solutions
FRCC
Yes
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Alan Adamson
New York State Reliability Council,
LLC
David Burke
Orange and Rockland Utilities Inc.
Greg Campoli
New York Independent System
Operator
Gerry Dunbar
Northeast Power Coordinating
Council
Regio
n
NPCC
Segme
nts
10
NPCC
3
NPCC
2
NPCC
10
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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238
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
NPCC
2
NPCC
9
NPCC
1
Paul Malozewski
Independent Electricity System
Operator
New Brunswick Power
Corporation
Hydro One Networks Inc.
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
NPCC
10
NPCC
5
Rob Vance
David Ramkalawan
Northeast Power Coordinating
Council
Ontario Power Generation, Inc.
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
Silvia Parada Mitchell
Northeast Power Coordinating
Council
NextEra Energy, LLC
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
239
Michael Forte
Sylvain Clermont
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
Si Truc Phan
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian O'Boyle
Peter Yost
NPCC
1
NPCC
1
NPCC
8
NPCC
3
Selected Answer:
No
Answer Comment:
The Implementation Plan should be modified to include clarification for
implementation of R4. Suggest adding the language used in the
Rationale for Requirement R4, which says: “Sixty‐full‐calendar months,
which begins on the effective date of the standard pursuant to the
implementation plan…”
The standard or the Implementation Plan should allow the RAS‐owner
sufficient time to mitigate a design deficiency identified as part of R4,
such as the lack of redundancy without removing the RAS from
service. Clarification should be provided to allow for continued
operation of an existing RAS after a single component failure scenario is
identified until a Corrective Action Plan can be completed.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
240
The Implementation Plan should address the possible scenario of a RAS
misoperation occurring within 120 days of the Standard’s effective date,
and if R5 would apply. Would this misoperation require the
development of a CAP after the effective date of the Standard? This
would apply for R6 and R7 as well.
For testing records will the RAS‐owner need to have documentation of
testing prior to the standard’s effective date? This should be clarified in
the Implementation Plan.
Response: Thank you for your comments.
The 60‐full calendar month interval in Requirement R4 begins on the effective date of PRC‐012‐2. The initial
performance of the requirement must be completed within the specified interval after the effective date of PRC‐012‐
2. The drafting team added language to the Implementation Plan, rationale box, and Supplemental Material section
of the standard to provide additional clarity.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. If a design deficiency is identified as part of the
Requirement R4 planning evaluation, the Planning Coordinator in conjunction with the Reliability should make the
decision whether or not to allow the RAS to remain in‐service until the Corrective Action Plan is completed.
Requirement R4 states that the entity shall analyze the RAS performance and provide the results of the analysis,
including any identified deficiencies, to its reviewing Reliability Coordinator(s) within 120 calendar days of a RAS
operation or failure of a RAS to operate when expected; therefore, the effective date of the standard is irrelevant.
Yes, Requirements R6 and R7 mandate a Corrective Action Plan be developed, submitted, and implemented.
The functional testing of a RAS is a new requirement; consequently, no records of functional testing prior to the
effective date of the standard are required.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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241
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2 ‐
Answer Comment:
N/A
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Selected Answer:
No
Answer Comment:
In the Implementation Plan, page 2, the following sentence has a
grammatical/mechanical issue: “As of the date of posting of this
Implementation Plan, however, the Commission has not issued an Final
Order approving and retirement the Reliability Standards enumerated
above.”
Response: Thank you for your comment.
The drafting team revised the language to reflect the issuance of FERC Order 818 approving the proposed standards
and definition of “Remedial Action Scheme.”
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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242
Selected Answer:
Eric Olson ‐ Transmission Agency of Northern California ‐ 1 ‐
Yes
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Selected Answer:
No
Answer Comment:
The Implementation Plan should allow the RAS‐owner sufficient time to
mitigate a design deficiency identified as part of R4, such as the lack of
redundancy without removing the RAS from service. Clarification
should be provided to allow for continued operation of those RAS, that
are already in service when the standard becomes effective, after a
single component failure scenario is identified until a Corrective Action
Plan can be completed.
Response: Thank you for your comment.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. If a design deficiency is identified as part of the
Requirement R4 planning evaluation, the Planning Coordinator in conjunction with the Reliability Coordinator should
make the decision whether or not to allow the RAS to remain in‐service until the Corrective Action Plan is completed.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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243
Yes
Andrew Gallo ‐ Austin Energy ‐ 6 ‐
Selected Answer:
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Selected Answer:
Yes
Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
LCRA Compliance
Group Member Name
Entity
Regio
n
Michael Shaw
LCRA
TRE
Teresa Cantwell
LCRA
TRE
Dixie Wells
LCRA
TRE
Segme
nts
6
1
5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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244
Selected Answer:
Yes
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP
Group Name:
Group Member Name
Shannon Mickens
Jason Smith
James Nail
Selected Answer:
SPP Standards Review Group
Entity
Regio
n
Southwest Power Pool Inc.
SPP
Segme
nts
2
Southwest Power Pool Inc
SPP
2
City of Independence, Missouri
SPP
3,5
Yes
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
245
Selected Answer:
Yes
Yes
Yes
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Selected Answer:
Yes
Jeff Wells ‐ Grand River Dam Authority ‐ 3 ‐
Selected Answer:
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
246
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1 ‐
Selected Answer:
No
Answer Comment:
The Implementation Plan should be modified to include clarification for
implementation of R4. Hydro One Networks Inc. agrees with the
NPCC’s TFSP in adding the language used in the Rationale box for R4,
which says: “Sixty‐full‐calendar months, which begins on the effective
date of the standard pursuant to the implementation plan…”
The standard or the Implementation Plan should allow the RAS‐owner
sufficient time to mitigate a design deficiency identified as part of R4,
such as the lack of redundancy without removing the RAS from
service. Clarification should be provided to allow for continued
operation of an existing RAS after a single component failure scenario is
identified until a Corrective Action Plan can be completed.
Response: Thank you for your comments.
The 60 full calendar month interval in Requirement R4 begins on the effective date of PRC‐012‐2. The initial
performance of the requirement must be completed within the specified interval after the effective date of PRC‐012‐
2. The drafting team added language to the Implementation Plan, rationale box, and Supplemental Material section
of the standard to provide additional clarity.
The drafting team asserts that the Reliability Coordinator is responsible for maintaining the operating reliability of
the Bulk Electric System within its Reliability Coordinator Area. If a design deficiency is identified as part of the
Requirement R4 planning evaluation, the Planning Coordinator in conjunction with the Reliability Coordinator should
make the decision whether or not to allow the RAS to remain in‐service until the Corrective Action Plan is completed.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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247
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
Group Name:
FMPA
Group Member Name
Entity
Regio
n
Tim Beyrle
City of New Smyrna Beach
FRCC
Jim Howard
Lakeland Electric
FRCC
Lynne Mila
City of Clewiston
FRCC
Javier Cisneros
Fort Pierce Utility Authority
FRCC
Randy Hahn
Ocala Utility Services
FRCC
Don Cuevas
Beaches Energy Services
FRCC
Stan Rzad
Keys Energy Services
FRCC
Matt Culverhouse
City of Bartow
FRCC
Tom Reedy
Florida Municipal Power Pool
FRCC
Steven Lancaster
Beaches Energy Services
FRCC
Mike Blough
Kissimmee Utility Authority
FRCC
Mark Brown
City of Winter Park
FRCC
Mace Hunter
Lakeland Electric
FRCC
Segme
nts
4
3
3
4
3
1
4
3
6
3
5
3
3
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
248
Selected Answer:
Yes
Answer Comment:
The Implementation Plan should specify when the first 5 year
evaluation required by R4 should be completed for an existing RAS.
Response: Thank you for your comment.
The 60 full calendar month interval in Requirement R4 begins on the effective date of PRC‐012‐2. The initial
performance of the requirement must be completed within the specified interval after the effective date of PRC‐012‐
2. The drafting team added language to the Implementation Plan, rationale box, and Supplemental Material section
of the standard to provide additional clarity.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
ACES Standards Collaborators
Group Member Name
Entity
Regio
n
Bob Solomon
Hoosier Energy Rural Electric
RFC
Cooperative, Inc.
Ginger Mercier
Prairie Power, Inc.
SERC
Ellen Watkins
Sunflower Electric Power
SPP
Corporation
Segme
nts
1
1,3
1
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249
Michael Brytowski
Great River Energy
Shari Heino
Brazos Electric Power Cooperative, TRE
1,5
Inc.
Arizona Electric Power
WECC 4,5
Cooperative, Inc.
Southwest Transmission
WECC 1
Cooperative, Inc.
John Shaver
John Shaver
MRO
1,3,5,6
Selected Answer:
No
Answer Comment:
We ask the SDT to clarify whether the approval process and the first
technical evaluation needs to be performed before or after the effective
date of the standard.
Response: Thank you for your comment.
The approval process associated with the RAS review can only take place after the effective date of the standard. The
60 full calendar month interval in Requirement R4 begins on the effective date of PRC‐012‐2. The initial performance
of the requirement must be completed within the specified interval after the effective date of PRC‐012‐2. The
drafting team added language to the Implementation Plan, rationale box, and Supplemental Material section of the
standard to provide additional clarity.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
250
Selected Answer:
Yes
7. If you have any other comments that you haven’t already provided in response to the above questions, please provide them
here.
Barbara Kedrowski ‐ WEC Energy Group, Inc. ‐ 3,4,5,6 ‐ RFC
Answer Comment:
We suggest that the standard have applicability to only the RAS entity,
normally the primary Transmission Owner for the region
affected. Including more than one party will make this standard too
cumbersome and difficult to manage. The primary application of a RAS
is to multi‐facility, wide‐area disturbances and as such is best vested in
the Transmission Owner, who has a wider “system” viewpoint than the
Generator Owner. We are concerned that Generator Owners may
become inadvertent RAS‐owners simply by owning a small fraction of
the equipment needed for the RAS, and thus become subject to
requirements R5 through R8, when they are typically passive parties to
the RAS.
Response: Thank you for your comment.
The drafting team maintains that RAS‐ownership should be according to component ownership. The RAS‐entity
owns the components that make up a RAS, and as the asset owner, is responsible for the purchase, design,
operation, maintenance, and testing of a RAS. This includes protection system components as well as non‐protection
system components. Otherwise, components may be left out of functional testing (R8), from single component
failure and malfunction evaluations (R4.1.3 and R4.1.4), and from operational analysis (R5) leading to reliability gaps.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
251
Based on comments, the drafting team revised the standard such that Requirements R5 and R6 apply to the RAS‐
entity. The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as
the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. As explained in
the Technical Justification, each separate RAS‐entity is obligated to participate in various activities, as identified by
the Requirements to the extent of their ownership. It is not the intent of the drafting team, however, to specify how
multiple RAS‐entities must coordinate.
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Answer Comment:
na
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 – MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Amy Casucelli
Xcel Energy
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1,3,5,6
MRO
1
MRO
1,3,5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
252
Theresa Allard
Minnkota Power Cooperative, Inc
MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative
MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
MRO
1,6
MRO
4
Larry Heckert
Western Area Power
Administration
Alliant Energy
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
3,4,5,6
Tony Eddleman
MRO
1,3,5
Answer Comment:
For R5, we propose revised wording that “within 120 days, or on a
mutually agree upon schedule.” This would allow earlier or later
completion of the analysis when warranted by unusual circumstances.
Response: Thank you for your comment.
The drafting team made the suggested change.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
253
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Answer Comment:
With regards to R5:
What is the benefit of providing the reviewing RC with results of a
successful RAS operation?
With regards to R8:
Although functional testing would verify that the scheme is working as
designed, there is no reason to believe that an RAS is any different from
another protection system i.e., it would need to be tested at intervals
outside the normal maintenance program. The testing of RAS should
fall in line with PRC‐005‐3 requirements for monitored systems and
unmonitored systems.
By requiring “at least once every six calendar years, each RAS‐owner
shall perform a functional test,” the drafting team is forcing all owners
of a RAS that has any Protection Systems in it to abandon the PRC‐005‐3
12 year Maximum Maintenance Intervals allowed in tables 1‐1, 1‐2, 1‐3,
1‐5, and 4.
If Requirement R9 is adopted as stated in this draft of the standard,
each segment of a RAS would have to be tested at a maximum interval
of 6 calendar years. This would require, for example, that voltage and
current sensing devices providing inputs to protective relays of a RAS
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“shall” be tested “at least once every six calendar years” instead of 12
Calendar years allowed in Table 1‐3 of PRC‐005‐3.
Response: Thank you for your comments.
The drafting team revised the standard to state that Requirement R5 only requires a RAS‐entity to provide the results
of RAS operational performance analysis if deficiencies were identified. Please see the revised requirements and
complementary revisions to the measures, rationale boxes, supplemental materials, and Attachments.
The drafting team revised the standard to allow RAS that have limited impact to have functional testing intervals of
up to twelve full calendar years. However, the drafting team contends that the six full calendar year interval is
appropriate for the higher impact RAS given the potential negative impact to BES reliability should a RAS operate
incorrectly. Existing regional practices include more frequent RAS functional testing than the proposed six full year
calendar interval. Requirement 8 in PRC‐012‐2 is only applicable to those non‐Protective System components used in
RAS. The drafting team contends these are the control components, such as programmable logic controllers (PLCs),
personal computers (PCs), multi‐function programmable relays, remote terminal units (RTUs), and logic processors
that have no applicability within PRC‐005.
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 – WECC
Group Name:
Seattle City Light Ballot Body
Group Member Name
Entity
Regio
n
Pawel Krupa
Seattle City Light
WECC
Segme
nts
1
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Dana Wheelock
Seattle City Light
WECC 3
Hao Li
Seattle City Light
WECC 4
Bud (Charles) Freeman
Seattle City Light
WECC 6
Mike haynes
Seattle City Light
WECC 5
Michael Watkins
Seattle City Light
WECC 1,3,4
Faz Kasraie
Seattle City Light
WECC 5
John Clark
Seattle City Light
WECC 6
Answer Comment:
1. We ask for a clarification on the PRC‐012‐2 definition of RAS Owner
to only “exclusively” include the owner of the scheme, and not include a
“participating” entity in the RAS operation. The participating entity
equipment would be covered by other standards such PRC‐005‐2 and
thus should be excluded from standard.
2. The requirement R8 will require that the RAS is tested every 6 years,
which is equivalent to any unmonitored relays that we have under PRC‐
005. However, testing the RAS may prove to be more laborious since it
will most likely require coordination among multiple participating
entities, so a more relaxed test sequence (12 years) would be preferred.
Response: Thank you for your comments.
Because of confusion between the terms, the drafting team consolidated the terms RAS‐owner and RAS‐entity. The
term RAS‐entity is now defined as the Transmission Owner, Generator Owner, or Distribution Provider that owns all
or part of a RAS. If the individual owners of a RAS decide that it would be advantageous for one RAS‐entity to
represent all of the other owners and assume a lead role in performing some of the required tasks, the standard
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does not prohibit this type of arrangement. Nevertheless, each RAS‐entity must still be able to demonstrate
compliance with the individual requirements the standard.
The drafting team revised the standard to allow RAS that have limited impact to have functional testing intervals of
up to twelve full calendar years. However, the drafting team contends that the six full calendar year interval is
appropriate for the higher impact RAS given the potential negative impact to BES reliability. Existing regional
practices include more frequent RAS functional testing than the proposed six full calendar year interval.
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Answer Comment:
RAS‐entity should be responsible for R5 instead of RAS‐owner. The
RAS‐entity, being designated to represent all RAS‐owners, is in the best
position to evaluate the operation of a RAS.
RAS‐entity should be responsible for R8 functional testing.
R9 should include a sub‐requirement for RCs to share their database
with neighboring RCs to provide coordination of RAS schemes near RC
borders.
Response: Thank you for your comments.
Because of confusion between the terms, the drafting team consolidated the terms RAS‐owner and RAS‐entity. The
term RAS‐entity is now defined as the Transmission Owner, Generator Owner, or Distribution Provider that owns all
or part of a RAS. If the individual owners of a RAS decide that it would be advantageous for one RAS‐entity to
represent all of the other owners and assume a lead role in performing some of the required tasks, the standard
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does not prohibit this type of arrangement. Nevertheless, each RAS‐entity must still be able to demonstrate
compliance with the individual requirements the standard.
The drafting team asserts that there is not a need for a requirement in PRC‐012 for an RC to share its RAS database
because information sharing among neighboring RCs is already covered in other NERC Reliability Standards.
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5
Answer Comment:
There are numerous references to components of a RAS scheme in the
standard and supplemental material, but there is no clear definition of
what constitutes a component of a RAS scheme. A lack of a clear
definition can lead to different interpretations of what a RAS
component is. For example, Requirement R4.3 requires that “the
possible inadvertent operation of the RAS resulting from any single RAS
component malfunctions satisfies all of the following” conditions in
4.3.1 thru 4.3.5. While it is implied that the RAS components could
include elements such as the RAS controller, communications, control
circuitry, supervisory relays or functions (breaker 52A contact), and/or
voltage or current sensing devices, it is not clearly stated. This leaves it
open for some entities to possibly consider additional items such as a
circuit breaker as a RAS component and other entities to not consider
it. It could also allow some entities to take a more relaxed approach
and exclude components that should possibly be included. A definition
or explanation of RAS components should be added to the standard
similar to the definitions used in PRC‐005‐4 (i.e. Automatic Reclosing
and Sudden Pressure Relaying).
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Response: Thank you for your comments.
The drafting team maintains that the team should not attempt to develop an exhaustive list of RAS components. An
exhaustive list of components is not practical given the variety that could be applied in RAS design and
implementation. See Item 4a in the Implementation Section of Attachment 1 in the Supplemental Material section
for typical RAS components for which redundancy may be considered. The RAS‐entity should have a clear
understanding of what components were applied to put a RAS into service and which were already present in the
system before a RAS was installed. The RC will make the final determination regarding which components should be
regarded as RAS components during its review.
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer Comment:
Currently as the standard is written, R5 and R6 require each RAS‐owner
to submit the results of the analysis and a CAP if needed. Tri‐State does
not believe it should be required that each RAS‐owner submit the
results and/or CAP rather than the RAS‐entity. The RAS‐entity can
collect the results and submit 1 report/CAP, instead of several individual
submittals from the seperate RAS‐owners.
Also, Tri‐State believes there is a numbering issue in Section II of
Attachment 1 of the standard. It looks like "Documentation showing
that the possible inadvertent operation of the RAS resulting from any
singles RAS component malfunction satisfies all of the following:"
should be #5 since it is a separate topic from #4.
Response: Thank you for your comments.
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Based on comments, the drafting team revised the standard such that R5 and R6 requirements apply to the RAS‐
entity. The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as
the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. As explained in
the Technical Justification, each separate RAS‐entity is obligated to participate in various activities, as identified by
the Requirements to the extent of their ownership. It is not the intent of the drafting team, however, to specify how
multiple RAS‐entities will coordinate.
The drafting team made the edit.
Maryclaire Yatsko ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5,6 ‐ FRCC
Answer Comment:
a. The Rationale Box for R6 states that the “RAS‐owner” will need to
submit information in Attachment 1 to the RC, should this be the RAS‐
entity?
b. In R6, if the RAS‐owner is the entity that performed the analysis in
R4 of R5, when does the 6 month clock start (i.e., when was it notified)?
c. For R7, is the intent that each RAS‐owner update the CAP with the
RC? It seems like this should be the job of the RAS‐entity, not multiple
RAS‐owners.
Response: Thank you for your comments.
Because of confusion between the terms, the drafting team consolidated the terms RAS‐owner and RAS‐entity. The
term RAS‐entity is now defined as the Transmission Owner, Generator Owner, or Distribution Provider that owns all
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or part of a RAS. If the individual owners of a RAS decide that it would be advantageous for one RAS‐entity to
represent all of the other owners and assume a lead role in performing some of the required tasks, the standard
does not prohibit this type of arrangement. Nevertheless, each RAS‐entity must still be able to demonstrate
compliance with the individual requirements the standard.
The drafting team revised Requirement R6 for clarification.
Yes, each RAS‐entity must implement the CAP as it relates to its facilities. The drafting team disagrees that only one
entity needs to be responsible.
Joshua Andersen ‐ Salt River Project ‐ 1,3,5,6 – WECC
Answer Comment:
As written the rationale for R8 is not incorporated into the requirement.
R8 rationale states that correct operation of a RAS segment would
qualify as a functional test. Please state that in the requirement so
there is no confusion or debate if a correct operation resets the time
frame necessary to perform a test.
SRP recommend the removal of the word “Requirement” in front of any
R# designation. R1 stands for Requirement 1 and is sufficient. Saying
"Requirement R1" is like saying Requirement Requirement 1. Also, the
term “Requirement” is not a defined term.
Response: Thank you for your comments.
The drafting team added language to the measure for Requirement 8 indicating that a correct operation of a RAS
segment would qualify as a functional test and the time frame for the segment that operated correctly would be
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reset. Segments that did not operate must be tested according to the planned testing schedule. In addition, the team
will include that in the RSAW for PRC‐012, Requirement R8.
The drafting team is adhering to the NERC style guide for Reliability Standards. Please address your comment to the
appropriate NERC staff.
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Answer Comment:
Please refer to RSC‐NPCC comments which Hydro‐Quebec TransEnergie
supports.
Response: Please see the drafting team’s responses to the referenced comments.
David Greene ‐ SERC ‐ 1,10 ‐ SERC
Group Name:
SERC PCS
Group Member Name
Entity
Regio
n
Steve Edwards
Dominion
SERC
Joel Masters
SCE&G
SERC
Segme
nts
1
1
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David Greene
SERC staff
SERC
10
Jammie Lee
MEAG
SERC
1
Greg Davis
GTC
SERC
1
Answer Comment:
If a RAS has multiple owners, and one or more owners is not compliant
to R8, does this mean that all owners, or the RAS‐entity, are non‐
compliant?
Response: Thank you for your comments.
Because of confusion between the terms, the drafting team consolidated the terms RAS‐owner and RAS‐entity. The
term RAS‐entity is now defined as the Transmission Owner, Generator Owner, or Distribution Provider that owns all
or part of a RAS. If the individual owners of a RAS decide that it would be advantageous for one RAS‐entity to
represent all of the other owners and assume a lead role in performing some of the required tasks, the standard
does not prohibit this type of arrangement. Nevertheless, each RAS‐entity must still be able to demonstrate
compliance with the individual requirements of the standard.
Bob Thomas ‐ Illinois Municipal Electric Agency ‐ 4 ‐
Answer Comment:
IMEA questions the need to include DP in the applicability. It is likely a
DP will only own a part of a RAS. It should be adequate to specify TO
coordination to verify RAS performance.
In R8, IMEA recommends deletion of "...and the proper operation of
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non‐Protection System components."; i.e., it should be adequate to
indicate only "...verify overall RAS performance."
Response: Thank you for your comments.
The drafting team declines to make the suggested change removing the Distribution Provider (DP). Given the critical
nature of RAS, every DP that owns all or part of a RAS must be held accountable to ensure BES reliability.
The focus of this requirement is verification of RAS functionality. Protection System components are addressed by
PRC‐005, but non‐Protection System components such as programmable logic controllers are not applicable under
PRC‐005 so the drafting team is including them in PRC‐012. The drafting team declines to make the suggested
change.
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1 ‐
Answer Comment:
• For R5, ATC proposes revising wording that “within 120 days, or on a
mutually agree upon schedule.” This would allow earlier or later
completion of the analysis when warranted by unusual circumstances.
• The purpose of Version 2 of PRC‐005 was to consolidate all
maintenance and testing of relays under one Standard. Having RAS
testing within PRC‐012‐2 would be contrary to that end. ATC addresses
this concern as follows:
Functional testing of RAS (as stated in Requirement 8 of PRC‐012‐2) is a
maintenance and testing activity that would be better included in the
PRC‐005 standard. The present PRC‐005‐2 Reliability Standard is the
maintenance standard that replaces PRC‐005‐1, 008, 011 and 017 and
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was designed to cover the maintenance of SPSs/RASs. However,
Reliability Standard PRC‐005‐2 lacks intervals and activities related to
non‐protective devices such as programmable logic controllers. ATC
recommends that a requirement for maintenance and testing of non‐
protective RAS components be added to a revision of PRC‐005‐2, rather
than be an outlying maintenance requirement located in the PRC‐012‐2
Standard.
Response: Thank you for your comments.
The drafting team made the suggested change.
The functional testing of a RAS to verify its performance is different from the maintenance activities associated with
the Protection System Components as detailed in the tables of PRC‐005. Requirement 8 of PRC‐012‐2 is only
applicable to those non‐Protective System components used in RAS. The drafting team contends these are the
control components, such as programmable logic controllers and are not Protection System Components and as
such, do not belong in PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through
component testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005.
The drafting team chose functional testing to emphasize the logic and control functions of RAS. The drafting team
contends that functional testing of the non‐Protection System RAS components in PRC‐012‐2 complements the
component testing of PRC‐005.
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Answer Comment:
Regarding the rationale for Requirement R8‐‐We agree with segmented
testing. However, the requirement does not state this and implies an
overall test should still be performed.
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R8 currently states:
At least once every six‐calendar years, each RAS‐owner shall perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non‐Protection System components.
Suggest revising to:
At least once every six‐calendar years, each RAS‐owner shall perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non‐Protection System components. This test
can be either:
o An end to end test encompassing all components and testing actual
functionality
o A segmented test to test all the components by grouping them
together into blocks until all parts of the RAS have been tested
Additional information in the Technical Guideline may be required to
explain how the six year cycle is measured when allowing segmented
testing. Segmented testing can test all components of an RAS every six
years, but an individual component could end up being tested once
every 10 years. For example, a RAS is designed so that it is comprised of
a segment “A”, and a segment “B”. Segment “A” is tested in year 1,
segment “B” is tested in year 5. As per Requirement R8 the RAS has
been tested within “six‐calendar years.” The clocks starts for the next
functional test period, and segment “B” is tested in year 1 (one year
since its first test), and segment “B” tested in year 5 (nine years since its
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first test). The RAS was tested within the “six‐calendar years”, but
segment “B” had a nine year interval. The requirement should be
modified to state that all segments shall be tested in the same calendar
year.
The RAS‐owner should be included in Attachment 3.
Response: Thank you for your comments.
The requirement mandates the overall RAS performance be verified, not that an overall test be conducted.
Furthermore, the rationale for Requirement R8 states: “Functional testing may be accomplished with end‐to‐end
testing or a segmented approach.” The drafting team is not specifying the method, only the reliability objective. The
drafting team declines to make the suggested change.
A more detailed description of the test intervals is now included in the Rationale and Supplementary Material. The
interval between tests begins on the date of the most recent successful test for each individual segment or end‐to‐
end test. A successful test of one segment only resets the test interval clock for that segment.
The consolidation of the terms RAS‐entity and RAS‐owner accomplish your suggestion.
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Answer Comment:
Peak was unable to locate the “consideration of comments” after the
last round of comments posted on the NERC website. The
“consideration of comments” are normally posted as part of the
Standards Drafting Process to help commenters understand the SDT
approach to comments made, and can affect subsequent comments
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submitted. Peak encourages NERC to post a “consideration of
comments” from all comment periods.
In Attachment 2 under I: Design bullet 6, it states that the effects of
future BES modifications… this seems to go outside of the scope of the
operating horizon on which the RC is focused.
Response: Thank you for your comments.
The drafting team did not post a response to comments received during the informal posting. The drafting team did
consider all of the comments in developing draft 1 of the standard subsequently posted in August.
Attachment 2 is a checklist of reliability‐related considerations for the Reliability Coordinator (RC) to review that is
based on Attachment 1 information provided by the RAS‐entity. The RC is not expected to perform planning analysis
but to review the information provided and assess whether future BES modifications have been adequately
considered in the RAS design. Furthermore, the RC may request assistance in RAS reviews from other parties such as
the PC or regional technical groups if necessary. The drafting team declines to modify this bullet in Attachment 2.
Kelly Dash ‐ Kelly Dash On Behalf of: Robert Winston, Con Ed ‐ Consolidated Edison Co. of New York, 3, 1, 5, 6
Answer Comment:
In the Rationale for Requirement R1, the last sentence of the first
paragraph is “A functional modification is any modification to a RAS
beyond the replacement of components that preserves the original
functionality.” How will “any modification to a RAS beyond the
replacement of components” preserve the original functionality? The
term “functional modification” requires clarification. Suggest
developing a formal definition:
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RAS Functional Modification‐‐a change to the resultant action for which
a RAS is designed.
Rationale for Requirement R8‐‐We agree with segmented
testing. However, the requirement does not state this and implies an
overall test should still be performed.
R8 currently states:
“At least once every six‐calendar years, each RAS‐owner shall perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non‐Protection System components.”
Suggest revising to:
“At least once every six‐calendar years, each RAS‐owner shall perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non‐Protection System components. This test
can be either:
• An end to end test encompassing all components and testing actual
functionality
• A segmented test to test all the components by grouping them
together into blocks until all parts of the RAS have been tested”
Additional information in the Technical Guideline may be required to
explain how the six year cycle is measured when allowing segmented
testing. Segmented testing can test all components of an RAS every six
years, but an individual component could end up being tested once
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every 10 years. For example, a RAS is designed so that it is comprised of
a segment “A” and a segment “B”. Segment “A” is tested in year 1,
segment “B” is tested in year 5. As per Requirement R8, the RAS has
been tested within “six‐calendar years.” The clocks starts for the next
functional test period and segment “B” is tested in year 1 (one year
since its first test) and segment “A” tested in year 5 (nine years since its
first test). The RAS was tested within the “six‐calendar years”, but
segment “A” had a nine year interval. Is this what is intended?
The RAS‐owner should be included in Attachment 3.
Response: Thank you for your comments.
The drafting team provided additional clarity for the term “functional modification” in the Rationale. Functional
modifications consist of any of the following:
Changes to System conditions or contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement of existing components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
Several additional examples are included in the Supplementary Material.
The drafting team declines to add the suggested language to the requirement. The objective of the requirement is to
test the overall performance of a RAS. This can be accomplished by several methods. The drafting team is not
specifying the method, only the reliability objective. The drafting team revised the Rationale and Supplemental
Material to provide additional clarity. The drafting team declines to add the suggested language to the requirement:
however, the team will include that in the RSAW for PRC‐012, Requirement R8.
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The drafting team received multiple comments seeking clarification relating to the RAS‐entity/owner. The drafting
team modified the Applicability section, consolidated the former terms RAS‐entity and RAS‐owner, and revised the
requirements to address these comments.
Mike Smith ‐ Manitoba Hydro ‐ 1 ‐
Answer Comment:
1. Regarding R1, it is not clear what the term “Functionally Modified”
means. “A functional modification is any modification to a RAS beyond
the replacement of components that preserves the original
functionality” does not make sense. Does changing some overall
scheme's functional logic without replacing any hardware device qualify
as “Functional Modified”?
2. R2 should be changed to “Each Reliability Coordinator that
receives Attachment 1 information pursuant to Requirement R1, shall,
within four‐full‐calendar months of receipt, or on a mutually agreed
upon schedule, perform a review of the RAS in accordance with
Attachment 2, and provide written feedback including any identified
reliability issues to the RAS‐entity”.
3. R3 should be changed to “Following the review performed
pursuant to Requirement R2 and receiving the feedback from the
reviewing RC, the RAS‐entity shall address each identified issue and
obtain approval from each reviewing Reliability Coordinator prior to
placing a new or functionally modified RAS in service or retiring an
existing RAS.
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4. R5 requires RAS owner to analyze the performance of every RAS
operations. It is not clear how much detail is required in this analysis.
For those RAS schemes that operates routinely and regularly as
designed, is a declaration of correct operation sufficient analysis?
5. R6 should be changed to “Within six‐full‐calendar months of
identifying or being notified of a deficiency in its RAS pursuant to
Requirement R4 or Requirement R5, each RAS‐owner shall participate in
developing a Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s)”.
Response: Thank you for your comments.
The drafting team provided additional clarity for the term “functional modification” in the Rationale. Functional
modifications consist of any of the following:
Changes to System conditions or contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement of existing components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
Several additional examples are included in the Supplementary Material.
The drafting team agrees and made the suggested change to Requirement R2.
The drafting team agrees and made the suggested change to Requirement R3. Please see the revised requirements
and complementary revisions to the measures, rationale boxes, supplemental materials, and Attachments.
The drafting team revised the standard such that Requirement R5 only requires a RAS‐entity to provide the results of
RAS operational performance analysis to the RC if deficiencies were identified. Please see the revised requirements
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and complementary revisions to the measures, rationale boxes, supplemental materials, and Attachments. The RAS‐
entity must verify that the RAS operated correctly; i.e., that Part 5.1 was satisfied.
The drafting team revised Requirement R6 such that it is in line with your suggestion.
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5 ‐
Answer Comment:
Reclamation suggests that the drafting team remove Generator Owners
from the applicability section of the standard. Reclamation is unclear
on how a Generator Owner could be considered to own all or part of a
RAS. Reclamation does not believe that Generator Owners are well
situated to analyze system‐level RAS impacts or be considered a RAS‐
entity.
Reclamation believes that a list of elements that may constitute
remedial action scheme elements would be helpful for understanding
the scope of the standard. Project 2010‐05.2, Phase 2 of Protection
Systems, defines RAS by listing elements which do not individually
constitute RAS. Reclamation is unclear on whether only protection
system elements are intended to be considered part of a RAS, or
whether elements affected by RAS operation like transmission lines or
generators may also be considered RAS elements. Reclamation
suggests the inclusion of a guidelines and technical basis section that
better defines the parameters of RAS that must be analyzed under R4
and R6, and their relationship to system elements affected by RAS.
Reclamation also suggests that the RAS‐entity should be responsible for
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the R5 analysis of each RAS operation or each failure of a RAS to
operate. As written, the requirement would impose duplicative analysis
requirements upon RAS owners that would not result in a
corresponding reliability benefit. In addition, Reclamation believes that
requiring each RAS‐owner to conduct an analysis of each RAS operation
is unwarranted because owners of one component of a RAS, such as a
Generator Owner, would not be in the best position to analyze the RAS
operation or its impact on the system. The RAS‐entity is the RAS‐owner
designated to represent all RAS‐owners for coordinating the review and
approval of a RAS. As outlined in the Technical Justifications, “[t]he
purpose of the RAS‐entity is to be the single information conduit with
each reviewing Reliability Coordinator (RC) for all RAS‐owners for each
RAS.” Reclamation believes the RAS analysis requirement should apply
to the entity best situated to analyze the overall RAS operation, the
RAS‐entity.
Finally, Reclamation suggests that the RAS‐entity should be responsible
for the R8 functional test of each RAS that is required at least once
every six calendar years. A RAS‐owner responsible for limited RAS
components would not be able to verify the overall RAS
performance. The RAS‐entity should be responsible for coordinating a
functional test with all RAS‐owners.
Response: Thank you for your comment.
The drafting team declines to make the suggested change removing the GO. Given the critical nature of RAS, all RAS
ownership must be accounted for in order to ensure BES reliability.
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The drafting team maintains that the team should not attempt to develop an exhaustive list of RAS components. An
exhaustive list of components is not practical given the variety that could be applied in RAS design and
implementation. See Item 4a in the Implementation Section of Attachment 1 in the Supplemental Material section
for typical RAS components for which redundancy may be considered. The RAS‐entity should have a clear
understanding of what components were applied to put a RAS into service and which were already present in the
system before a RAS was installed. The RC will make the final determination regarding which components should be
regarded as RAS components during its review.
The drafting team revised the standard such that Requirement R5 applies to the RAS‐entity. The drafting team
consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the Transmission Owner,
Generator Owner, or Distribution Provider that owns all or part of a RAS. As explained in the Technical Justification,
each separate RAS‐entity is obligated to participate in various activities, as identified by the Requirements to the
extent of their ownership. It is not the intent of the drafting team, however, to specify how multiple RAS‐entities will
coordinate.
Each separate RAS‐entity is obligated to participate in various activities, as identified by the Requirements to the
extent of their ownership.
Anthony Jablonski ‐ ReliabilityFirst ‐ 10 ‐
Answer Comment:
1. Applicability Section:
i. ReliabilityFirst believes the “RAS‐entity” functional entity under the
“Applicability” section may cause issues regarding which entity is
responsible for requirements related to the “RAS‐entity”. Absent any
requirements requiring the RAS‐owners to designate and make known
the official RAS‐entity, it may be difficult to assess compliance on the
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275
RAS‐entity. ReliabilityFirst recommends including a new Requirement
R1 as follows:
a. R1. For each RAS that is owned by multiple RAS‐owners, the
RAS‐owners shall designate one RAS‐entity and inform the Reliability
Coordinator(s) and Transmission Planner(s) that coordinates the area(s)
where the RAS is located of such designation
2. Requirement R5
i. As written, if there are multiple RAS‐owners of a RAS, the
expectation is to have multiple analyses performed. ReliabilityFirst
believes it would be more appropriate to require the RAS‐entity to
perform one analysis with coordination of all associated RAS‐owners.
3. Requirement R8
i. Requirement R8 requires each RAS‐owner to perform a functional
test of each RAS. As written, in the case where multiple RAS‐owners
own a single RAS, multiple tests of the same RAS would be required to
be run. ReliabilityFirst believes in cases where a RAS is owned by
multiple RAS‐owners, a single test should be required by the designated
RAS‐entity in conjunction with all the RAS‐owners.
4. VSL for Requirement R4
i. The time frames for the VSL for Requirement R4 are not all
inclusive. For example, the Lower VSL states “less than 61‐fullcalendar
months” while the moderate VSL states “greater than 61‐full‐calendar
months”. In this example it is unclear which VSL category an entity falls
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276
under if they perform the evaluation in 61 months. Listed below is an
example of the Lower VSL for the SDT’s consideration.
a. The Transmission Planner performed the evaluation in
accordance with Requirement R4, but in greater than 60‐full‐calendar
months but less than [or equal to] 61‐fullcalendar months.
5. VSL for Requirement R7
i. The Lower VSL states that if an entity failed both 7.2 and 7.3 they
would fall under the Lower category. ReliabilityFirst questions what VSL
an entity would fall under in the scenario where an entity is compliant
with 7.2 but not 7.3?
▪ The RAS‐owner implemented a CAP (Part 7.1), but failed to
update the CAP (Part 7.2) if actions or timetables changed [OR] failed to
notify one or more of the reviewing Reliability Coordinator(s) (Part 7.3),
in accordance with Requirement R7.
Response: Thank you for your comments.
The drafting team disagrees with your proposed changes. The drafting team consolidated the terms RAS‐owner and
RAS‐entity. The term RAS‐entity is now defined as the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS. As explained in the Technical Justification, each separate RAS‐entity is
obligated to participate in various activities, as identified by the Requirements to the extent of their ownership. It is
not the intent of the drafting team, however, to specify how multiple RAS‐entities will coordinate.
The drafting team corrected the VSLs for Requirements R4 and R7.
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277
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐
Group Name:
IRC Standards Review Committee
Group Member Name
Entity
Regio Segme
n
nts
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC 2
Greg Campoli
NYISO
NPCC 2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC 2
Lori Spence
MISO
MRO 2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC 2
Answer Comment:
Requirement R5: The SRC agrees that the RAS entity should evaluate
RASs under the circumstances identified in Requirement R5, but would
suggest that such entities be required to provide the results of such
assessments to their Reliability Coordinator and Planning Coordinator.
Requirement R9: In conjunction with the comment provided under Q2
to replace the TP with the PC, while the SRC agrees that the RC is the
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278
appropriate entity to maintain the database, it suggests that the
Reliability Coordinator be required to share its database with the
applicable Planning Coordinator(s) as some entities may have a need for
planned RAS information for modeling and to ensure that appropriate
information is shared across the long‐ and short‐term horizons.
Response: Thank you for your comments.
The drafting team revised Requirement R5 such that the RAS‐entity provides the results of RAS operational
performance analyses that identified any deficiencies to the RC. The RAS‐entity would be expected to engage other
parties such as its Transmission Planner or Planning Coordinator as necessary to develop a CAP in response to a RAS
for which performance issues were identified. The drafting team declines to make the change.
The rationale for Requirement R9 states: The database enables the RC to provide other entities high‐level
information on existing RAS that can potentially impact operational and/or planning activities of an entity. The
drafting team declines to make the suggested change.
Likes:
Dislikes:
1
Electric Reliability Council of Texas, Inc., 2, Axson Elizabeth
0
Oliver Burke ‐ Entergy ‐ Entergy Services, Inc. ‐ 1 ‐
Answer Comment:
Entergy supports the SERC PCS comments on this standard.
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279
Response: Please see the drafting team’s responses to the referenced comments.
Mark Kenny ‐ Eversource Energy ‐ 3 ‐
Answer Comment:
Regarding the Applicability Section 4.1.4 for the RAS‐entity, who
designates the RAS‐owner to represent all RAS‐owner(s)?
In the Rationale for Requirement R1, last sentence of the first
paragraph, “A functional modification is any modification to a RAS
beyond the replacement of components that preserves the original
functionality.” How will “any modification to a RAS beyond the
replacement of components” preserve the original
functionality? Functional modification requires clarification. Suggest
developing a formal definition:
RAS Functional Modification‐‐a change to the resultant action for which
a RAS is designed.
Rationale for Requirement R8‐‐We agree with segmented
testing. However, the requirement does not state this and implies an
overall test should still be performed.
R8 currently states:At least once every six‐calendar years, each RAS‐
owner shall perform a functional test of each RAS to verify the overall
RAS performance and the proper operation of non‐Protection System
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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280
components.
Suggest revising to: At least once every six‐calendar years, each RAS‐
owner shall perform a functional test of each RAS to verify the overall
RAS performance and the proper operation of non‐Protection System
components. This test can be either:
o An end to end test encompassing all components and testing actual
functionality
o A segmented test to test all the components by grouping them
together into blocks until all parts of the RAS have been tested
Additional information in the Technical Guideline may be required to
explain how the six year cycle is measured when allowing segmented
testing. Segmented testing can test all components of an RAS every six
years, but an individual component could end up being tested once
every 10 years. For example, a RAS is designed so that it is comprised of
a segment “A”, and a segment “B”. Segment “A” is tested in year 1,
segment “B” is tested in year 5. As per Requirement R8 the RAS has
been tested within “six‐calendar years.” The clocks starts for the next
functional test period, and segment “B” is tested in year 1 (one year
since its first test), and segment “B” tested in year 5 (nine years since its
first test). The RAS was tested within the “six‐calendar years”, but
segment “B” had a nine year interval. Is this what is intended?
The RAS‐owner should be included in Attachment 3.
R8 and guidance provided in the supplemental material as written
appears to overstep the direction provided by the SAR which states that
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281
the standard will address maintenance and testing on non‐Protection
System components of a RAS. Maintenance of Protection Systems
installed as a RAS for BES reliability is clearly covered in PRC‐005. NPCC
is very concerned that there are different timeframes and duplicative
testing for RAS components. In particular, the supplemental material
provided is very confusing and appears to suggest duplicative testing
compared to testing already required in PRC‐005. NPCC suggests that
all testing requirements for RAS should be contained in one standard.
NPCC suggests deletion of the phase “including any identified
deficiencies” in R5 because requirements R5.1 through R5.4 clearly
define the necessary level of analysis required by the RAS‐
owner. Leaving this phrase in will lead to confusion over whether the
proper operation of a “composite” RAS is considered a deficiency if one
of the two redundant RAS suffer a component failure.
Response: Thank you for your comments.
The drafting team received multiple comments seeking clarification relating to the RAS‐entity/owner. The drafting
team modified the Applicability section, consolidated the former terms RAS‐entity and RAS‐owner, and revised the
requirements to address these comments.
The drafting team provided additional clarity for the term “functional modification” in the Rationale. Functional
modifications consist of any of the following:
Changes to System conditions or contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement of existing components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
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282
Several additional examples are included in the Supplementary Material.
The drafting team declines to add the suggested language to the requirement. The objective of the requirement is to
test the overall performance of a RAS. This can be accomplished by several methods. The drafting team is not
specifying the method, only the reliability objective. The drafting team revised the Rationale and Supplemental
Material to provide additional clarity. The drafting team declines to add the suggested language to the requirement:
however, the team will include that in the RSAW for PRC‐012, Requirement R8.
A more detailed description of the test intervals is now included in the Rationale and Supplementary Material. The
interval between tests begins on the date of the most recent successful test for each individual segment or end‐to‐
end test. A successful test of one segment only resets the test interval clock for that segment. The objective of the
requirement is to test the overall performance of a RAS. This can be accomplished by several methods. The drafting
team is not specifying the method, only the reliability objective. The drafting team revised the Rationale and
Supplemental Material to provide additional clarity.
The drafting team regrets any confusion caused by the examples included in the supplemental material. The
supplemental material has been revised to better demonstrate the relationship between PRC‐005 component testing
and PRC‐012‐2 functional testing. The drafting team disagrees with the addition of functional testing to PRC‐005.
Requirement 8 in PRC‐012‐2 is only applicable to those non‐Protective System components used in RAS. The drafting
team contends these are the control components, such as programmable logic controllers, that have no applicability
within PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through component
testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005. The drafting
team chose functional testing to emphasize the logic and control functions of RAS and contends that functional
testing of the non‐Protection System RAS components in PRC‐012‐2 complements the component testing of PRC‐
005. The drafting team revised the standard to allow RAS that have limited impact to have functional testing
intervals of up to twelve full calendar years. However, the drafting team contends that the six full calendar year
interval is appropriate for the higher impact RAS given the potential negative impact to BES reliability should a RAS
operate incorrectly. Existing regional practices include more frequent RAS functional testing than the proposed six
full calendar year interval.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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283
Requirements R5.1.1 through 5.1.4 (R5.1 through R5.4 in the previously posted draft of PRC‐012‐2) state the scope of
the RAS operational performance, and therefore any “deficiencies” identified and reported to the RC per
Requirement R5.2 are with respect to these. The drafting team contends that if the RAS appropriately triggers for the
system conditions for which it was designed, and provides the desired response as designed, that a component
failure in one of two redundant RAS would not constitute a deficiency with respect to the operational analysis
described in Requirement R5. It would be expected, however, that if such a component failure was identified, the
RAS‐entity would be incented to repair the failed component as soon as possible to avoid the risk of the RAS failing to
operate for a future event. The drafting team declines to make the suggested change.
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5 ‐
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio Segme
n
nts
Larry Nash
Dominion Virginia Power
SERC 1
Louis Slade
Dominion Resources, Inc.
SERC 6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC 5
Answer Comment:
Attachment 1, Section III‐Implementation states, “5. Documentation
describing the functional testing process.” Dominion recommends
deleting this bullet. This information is not necessarily available during
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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284
the preliminary design phase. The approval of the design is sought prior
to detailed engineering. (Planning)
In R5 it states that the RAS owner analyzes the event, but in flow chart
it states RAS owner and TP. Dominion suggests that the content in the
Flow Chart be consistent with language of the Requirement.
R5 references the timeframe “within 120 calendar days”, however in
other areas of the document the time frame is stated to be “within XX
calendar months”. Dominion suggests updating the document to
reflect the actual timeframe. Dominion also believes consistency is
needed and suggests the timeframes reflect "full calendar months”
versus “months”.
Response: Thank you for your comments.
Thank you for your comment. The drafting team contends that sufficient information be provided to the RC to allow
a proper review including information describing the RAS‐entity’s plan for periodic testing. The drafting team
declines to make the suggested change.
The drafting team revised the Flowchart.
The drafting team added “mutually agreed upon schedule” to allow more time for the RAS operational analysis to be
performed and added the modifier “full” to calendar days. The timeframe of 120 full calendar days is consistent with
a similar requirement in PRC‐004‐5.
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
285
Group Name:
PSEG
Group Member Name
Joseph Smith
Jeffrey Mueller
Tim Kucey
Karla Jara
Answer Comment:
Entity
Regio
n
Public Service Electric and Gas
RFC
Segme
nts
1
Public Service Electric and Gas Co.
RFC
3
PSEG Fossil LLC
RFC
5
PSEG Energy Resources & Trade
LLC
RFC
6
1. In addition to RAS‐entity’s, RAS‐owners also have compliance
obligations. Yet RAS‐owners are not identified in any of the
attachments. In addition, the RAS‐related equipment of each owner
should be identified in one attachment for use by the Reliability
Coordinator, the Transmission Planner, and the Compliance
Enforcement Authority. Expanding Attachment 3 may be the most
efficient way to address these concerns.
2. R5 should be modified by changing this phrase: “…analyze the RAS
performance…” to “analyze the performance of its RAS‐related
equipment.” In cases where there are multiple RAS owners, a single
RAS‐owner cannot analyze the performance of the entire RAS; it can
only analyze the performance of its own RAS‐related equipment.
Response: Thank you for your comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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286
The drafting team received multiple comments seeking clarification relating to the RAS‐entity/owner. The drafting
team consolidated the former terms RAS‐entity and RAS‐owner in the Applicability section, revised the requirements
and Supplemental Material section of the standard to address these comments.
The drafting team maintains that the team should not attempt to develop an exhaustive list of RAS components. An
exhaustive list of components is not practical given the variety that could be applied in RAS design and
implementation. See Item 4a in the Implementation Section of Attachment 1 in the Supplemental Material section
for typical RAS components for which redundancy may be considered. The RAS‐entity should have a clear
understanding of what components were applied to put a RAS into service and which were already present in the
system before a RAS was installed. The RC will make the final determination regarding which components should be
regarded as RAS components during its review.
Each separate RAS‐entity is obligated to participate in various activities, as identified by the Requirements to the
extent of their ownership. The drafting team revised the Rationale and Supplemental Material to provide additional
clarity.
Likes:
4
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Richard Hoag ‐ FirstEnergy ‐ FirstEnergy Corporation ‐ 1,3,4,5,6 ‐ RFC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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287
Group Name:
FE RBB
Group Member Name
Entity
Regio
n
William Smith
FirstenergyCorp
RFC
Cindy Stewart
FirstEnergy Corp.
RFC
Doug Hohlbaugh
Ohio Edison
RFC
Robert Loy
FirstEnergy Solutions
RFC
Richard Hoag
FirstenergyCorp
RFC
Ann Ivanc
FirstEnergy Solutions
FRCC
Segme
nts
1
3
4
5
NA ‐
Not
Applica
ble
6
Answer Comment:
FirstEnergy would like additional clarification on the phrase “RAS
controller” in the second paragraph of the Supplemental Material
section in “Applicability”, 4.1.4 RAS‐entity.
Additionally, FirstEnergy seeks to confirm that if a RAS system operates
as planned/designed durnng normal operations then can the data from
this actual operation be used to verify/satisfy testing requirements?
Response: Thank you for your comments.
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288
The drafting team received multiple comments seeking clarification relating to the RAS‐entity/owner. The drafting
team consolidated the former terms RAS‐entity and RAS‐owner in the Applicability section, revised the requirements
and Supplemental Material section of the standard to address these comments.
The drafting team added the language to the measure for Requirement 8 indicating that a correct operation of a RAS
segment would qualify as a functional test for that segment. In addition, the team will include that in the RSAW for
PRC‐012, Requirement R8.
Lee Pedowicz ‐ Northeast Power Coordinating Council ‐ 10 ‐ NPCC
Group Name:
NPCC‐‐Project 2010‐05.3 Submitted 10‐5‐15
Group Member Name
Entity
Alan Adamson
New York State Reliability Council,
LLC
David Burke
Orange and Rockland Utilities Inc.
Greg Campoli
New York Independent System
Operator
Gerry Dunbar
Northeast Power Coordinating
Council
Mark Kenny
Northeast Utilities
Helen Lainis
Independent Electricity System
Operator
Regio
n
NPCC
Segme
nts
10
NPCC
3
NPCC
2
NPCC
10
NPCC
1
NPCC
2
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289
Rob Vance
Paul Malozewski
New Brunswick Power
Corporation
Hydro One Networks Inc.
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
NPCC
10
NPCC
5
NPCC
9
NPCC
1
David Ramkalawan
Northeast Power Coordinating
Council
Ontario Power Generation, Inc.
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities Inc.
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
NPCC
10
NPCC
5
NPCC
10
NPCC
5
Connie Lowe
Guy Zito
Silvia Parada Mitchell
Northeast Power Coordinating
Council
NextEra Energy, LLC
Robert Pellegrini
The United Illuminating Company
NPCC
1
Kathleen Goodman
ISO ‐ New England
NPCC
2
Kelly Dash
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
NPCC
1
Michael Forte
NPCC
1
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November 25, 2015
290
Brian O'Boyle
NPCC
Sylvain Clermont
Consolidated Edison Co. of New
York, Inc.
Consolidated Edison Co. of New
York, Inc.
Hydro‐Quebec TransEnergie
Si Truc Phan
Peter Yost
8
NPCC
3
NPCC
1
Hydro‐Quebec TransEnergie
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Michael Jones
National Grid
NPCC
1
Answer Comment:
Because feeder loading can be changed intentionally, it is frequent to
add, substitute, or remove load tripping devices (not distributed relays)
in order to maintain the amount of load that is required by a load
tripping RAS. Would these changes constitute a RAS functional
modification? If so, suggest revising the definition of RAS functional
modification. The Attachment 1 procedure that would have to be
applied would be overly burdensome.
Regarding the Applicability Section 4.1.4 for the RAS‐entity, who
designates the RAS‐owner to represent all RAS‐owner(s)?
In the Rationale for Requirement R1, last sentence of the first
paragraph, “A functional modification is any modification to a RAS
beyond the replacement of components that preserves the original
functionality.” How will “any modification to a RAS beyond the
replacement of components” preserve the original
functionality? Functional modification requires clarification. Suggest
developing a formal definition:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
November 25, 2015
291
RAS Functional Modification‐‐a change to the resultant action for which
a RAS is designed.
Rationale for Requirement R8‐‐We agree with segmented
testing. However, the requirement does not state this and implies an
overall test should still be performed.
R8 currently states:
At least once every six‐calendar years, each RAS‐owner shall perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non‐Protection System components.
Suggest revising to:
At least once every six‐calendar years, each RAS‐owner shall perform a
functional test of each RAS to verify the overall RAS performance and
the proper operation of non‐Protection System components. This test
can be either:
o An end‐to‐end test encompassing all components and testing
actual functionality
o A segmented test to test all the components by grouping them
together into blocks until all parts of the RAS have been tested
Additional information in the Technical Guideline may be required to
explain how the six year cycle is measured when allowing segmented
testing. Segmented testing can test all components of an RAS every six
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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292
years, but an individual component could end up being tested once
every 10 years. For example, a RAS is designed so that it is comprised of
a segment “A”, and a segment “B”. Segment “A” is tested in year 1,
segment “B” is tested in year 5. As per Requirement R8 the RAS has
been tested within “six‐calendar years.” The clock starts for the next
functional test period, and segment “B” is tested in year 1 (one year
since its first test), and segment “A” tested in year 5 (nine years since its
first test). The RAS was tested within the “six‐calendar years”, but
segment “A” had a nine year interval. Is this what is intended? It
should be required that all segments be tested in the same calendar
year.
The RAS‐owner should be included in Attachment 3.
Requirement R8 and guidance provided in the supplemental material as
written go beyond the direction stipulated by the SAR which states that
the standard will address maintenance and testing on non‐Protection
System components of a RAS. Maintenance of Protection Systems
installed as a RAS for BES reliability is clearly covered in PRC‐005. We
are very concerned that there are different timeframes and duplicative
testing for RAS components. In particular, the supplemental material
provided is very confusing and appears to suggest duplicative testing
compared to testing already required by PRC‐005. Suggest that all
testing requirements for RAS should be contained in one standard. The
testing time periods should be made consistent with Table 1‐1 in PRC‐
005, specifically 6 years for an unmonitored protection system, and 12
years for an unmonitored microprocessor protection system.
NPCC suggests deletion of the phase “including any identified
deficiencies” in R5 because Parts 5.1 through 5.4 clearly define the
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293
necessary level of analysis required by the RAS‐owner. Leaving this
phrase in will lead to confusion over whether the proper operation of a
“composite” RAS is considered a deficiency if one of the two redundant
RAS suffer a component failure.
In C. Compliance, Section 1.2 Evidence Retention: the RC and TP have
not been included. The TO, GO and DP are requested to keep data for
requirements that they might not be responsible for.
Response: Thank you for your comments.
The drafting team provided additional clarity for the term “functional modification” in the Rationale. Functional
modifications consist of any of the following:
Changes to System conditions or contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement of existing components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e. addition or removal
Several additional examples are included in the Supplementary Material.
A more detailed description of the test intervals is now included in the Rationale and Supplementary Material. The
interval between tests begins on the date of the most recent successful test for each individual segment or end‐to‐
end test. A successful test of one segment only resets the test interval clock for that segment.
The drafting team consolidated the former terms RAS‐entity and RAS‐owner in the Applicability section, revised the
requirements and Supplemental Material section of the standard to address these comments.
The functional testing of a RAS to verify its performance is different from the maintenance activities associated with
the Protection System Components as detailed in the tables of PRC‐005. Requirement 8 of PRC‐012‐2 is only
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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294
applicable to those non‐Protective System components used in RAS. The drafting team contends these are the
control components, such as programmable logic controllers and are not Protection System Components and as
such, do not belong in PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through
component testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005.
The drafting team chose functional testing to emphasize the logic and control functions of RAS. The drafting team
contends that functional testing of the non‐Protection System RAS components in PRC‐012‐2 complements the
component testing of PRC‐005.
Requirements R5.1.1 through 5.1.4 (R5.1 through R5.4 in the previously posted draft of PRC‐012‐2) state the scope of
the RAS operational performance, and therefore any “deficiencies” identified and reported to the RC per
Requirement R5.2 are with respect to these. The drafting team contends that if the RAS appropriately triggers for the
system conditions for which it was designed, and provides the desired response as designed, that a component
failure in one of two redundant RAS would not constitute a deficiency with respect to the operational analysis
described in Requirement R5. It would be expected, however, that if such a component failure was identified, the
RAS‐entity would be incented to repair the failed component as soon as possible to avoid the risk of the RAS failing to
operate for a future event. The drafting team declines to make the suggested change.
The drafting team declines to add the suggested language to the requirement. The objective of the requirement is to
test the overall performance of a RAS. This can be accomplished by several methods. The drafting team is not
specifying the method, only the reliability objective. The drafting team revised the Rationale and Supplemental
Material to provide additional clarity.
The drafting team regrets any confusion caused by the examples included in the supplemental material. The
supplemental material has been revised to better demonstrate the relationship between PRC‐005 component testing
and PRC‐012‐2 functional testing. The drafting team disagrees with the addition of functional testing to PRC‐005.
Requirement 8 in PRC‐012‐2 is only applicable to those non‐Protective System components used in RAS. The drafting
team contends these are the control components, such as programmable logic controllers, that have no applicability
within PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through component
testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005. The drafting
team chose functional testing to emphasize the logic and control functions of RAS and contends that functional
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testing of the non‐Protection System RAS components in PRC‐012‐2 complements the component testing of PRC‐
005. The drafting team revised the standard to allow RAS that have limited impact to have functional testing intervals
of up to twelve full calendar years. However, the drafting team contends that the six full calendar year interval is
appropriate for the higher impact RAS given the potential negative impact to BES reliability should a RAS operate
incorrectly. Existing regional practices include more frequent RAS functional testing than the proposed six full
calendar year interval.
The Compliance section has been modified to correct the issues you identified.
Rick Applegate ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 6 ‐
Answer Comment:
Tacoma Power recommends that the definition of ‘RAS‐owner’ be
limited to functional ownership, as opposed to component
ownership. For example, if one company owns a station DC supply,
some wiring, and trip coil, but another company owns the control
device at the same location, the entity that owns the control device
should be a RAS‐owner, and the entity that owns the station DC supply,
wiring, and trip coil should not be a RAS‐owner. Another example
would be an entity that owns sensing devices that another entity uses
to provide inputs to a relay or PLC that it owns; the entity that owns the
sensing devices in this example should not be a RAS‐owner. Yet
another example is when one entity owns a portion of the
communications system; simply owning part of the communications
system should not make the entity a RAS‐owner.
In the Q & A document, section 9, top of page 6, what if timing is only
critical on the order of minutes (e.g., remediation of thermal
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overload). Could replacement of a T1 multiplexor possibly not be
considered a RAS functional change in this case?
In the Q & A document, section 9, page 6, the example of “replacement
of a failed RAS component with an identical component” seems overly
exclusive. It is recommended to replace “identical” with “substantially
identical.”
In Requirement R6, why is “six‐full calendar months,” instead of simply
“six calendar months,” used?
In the Supplemental Material section, page 27, the following sentence
has a grammatical/mechanical issue: “A RAS is only allowed to drop
non‐consequential load or interrupt Firm Transmission Service can do
that only if that action is allowed for the Contingency for which it is
designed.”
In the Supplemental Material section, page 28, the following passage
does not seem to read well: “These changes could result in inadvertent
activation of that output, therefore, tripping too much load and result
in violations of Facility Ratings. Alternatively, the RAS might be designed
to trip more load than necessary (i.e., “over trip”) in order to satisfy
single‐component‐failure requirements. System changes could result in
too little load being tripped at affected locations and result in
unacceptable BES performance if one of the loads failed to
trip.” Should the middle sentence be removed? It seems incongruous
with the other two sentences.
In the Supplemental Material section, page 29, would a CAP be required
if equipment fails that is readily replaceable/repairable? Tacoma Power
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maintains that CAP’s should be required for issues that will require a
longer time to address. In general, notification of RAS equipment
failures is addressed by other standards.
In the Supplemental Material section, page 30, change “the , the” to
“then, the.”
Response: Thank you for your comments.
The drafting team disagrees with your proposed change. The drafting team contends that basing RAS ownership on
function rather than components could lead to reliability gaps. The RAS‐entity owns the facilities, and as the asset
owner is responsible for the purchase, design, operation, and testing of a RAS. The drafting team contends your
examples strengthen the case for the asset owner to be the responsible entity.
The drafting team modified the example in the Q & A document of replacing a T1 multiplexor to indicate that a
resulting change in timing would be a functional modification only if it may be important to the timing of the RAS.
The drafting team added “. . . , or a component that uses the same functionality as the failed component.” Other
examples were also added to the Supplementary Material.
The “full” allows any fractional month, possibly adding as much as another month.
The drafting team revised the sentence.
The drafting team modified the wording of this section for clarity.
The drafting team contends that even a RAS equipment failure that is readily replaceable/repairable should be
documented. Such a CAP may be as simple as an email to the RC to the effect of “Found failed auxiliary relay.
Replaced failed auxiliary relay with a spare. Repairs completed on [date].”
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The drafting team made the editorial change.
Eric Olson ‐ Transmission Agency of Northern California ‐ 1 ‐
Answer Comment:
Although neither the Applicability section nor the Requirements of this
draft standard distinguish between Protection System components and
non‐Protection System components of a RAS, the associated supporting
information does make such a distinction. For example, the first
paragraph of the Background Information section on the Unofficial
Comment Form includes the following:
“The maintenance of the Protection System components associated with
RAS (PRC‐017‐1 Remedial Action Scheme Maintenance and Testing) are
already addressed in PRC‐005. PRC‐012‐2 addresses the testing of the
non‐Protection System components associated with RAS/SPS.”
NERC’s supporting information elsewhere suggests that examples of
non‐Protection System components include programmable logic
controllers, computers, and the control functions of microprocessor
relays.
Based on TANC’s understanding of NERC’s intent for this standard, we
suggest that NERC modify the definition of RAS‐owner that is provided
in the standard’s Applicability section to the following.
“RAS‐owner ‐ the Transmission Owner, Generator Owner, or Distribution
Provider owns all or part of the non‐Protection System components of a
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RAS” (bold text is added to current proposed definition).
TANC’s proposed modified definition would clarify that this standard
and its requirements are not applicable to a Transmission Owner,
Generator Owner, or Distribution Provider that doesn’t own any non‐
Protection System components of a RAS.
Response: Thank you for your comment.
The drafting team declines to make the suggested change. The drafting team consolidated the former terms RAS‐
entity and RAS‐owner in the Applicability section, revised the requirements and Supplemental Material section of the
standard to address these comments.
Leonard Kula ‐ Independent Electricity System Operator ‐ 2 ‐
Answer Comment:
Requirement R9: In conjunction with our comment under Q2 to replace
TP with PC, while we agree that the RC is the appropriate entity to
maintain the database, we suggest adding the Planning Coordinator to
this requirement for RASs that have been planned and evaluated in the
long‐term planning timeframe. Some entities may have a need for
planned RAS information for modeling.
We recommend that the standard should recognize that all RAS are not
equal and therefore should not need the same level of design review (as
per R1), performance requirement in case of RAS failure (as per 4.4),
and operation analysis (as per R5). We suggest defining two or more
“class” or “type” for RAS based on the impact of their misoperation or
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failure to operate on the system performance. Different class or type of
RAS will then have different levels of design, performance and analysis
requirements.
R8 and guidance provided in the supplemental material as written
appears to overstep the direction provided by the SAR which states that
the standard will address maintenance and testing on non‐Protection
System components of a RAS. Maintenance of Protection Systems
installed as a RAS for BES reliability is clearly covered in PRC‐005. The
IESO is very concerned that there are different timeframes and
duplicative testing for RAS components. In particular, the supplemental
material provided is very confusing and appears to suggest duplicative
testing compared to testing already required in PRC‐005. The IESO
suggests that all testing requirements for RAS should be contained in
one standard. NERC PRC‐005 applies to Protection Systems installed as
Remedial Action Schemes for BES reliability. As such, all RAS Protective
Relays, Communication Systems, Voltage and Current Sensing Devices
Providing Inputs to Protective Relays, Control Circuitry, DC Supply,
alarms and Automatic Reclosing Components are already included in
PRC‐005. Lastly, this requirement would force entities to perform
testing on local area schemes; yet non‐BES components are not subject
to maintenance requirements under NERC PRC‐005. Typing would be a
good mythology to distinguish which RAS schemes should be subject to
the strict maintenance requirements.
The IESO suggests deletion of the phase “including any identified
deficiencies” in R5 because requirements R5.1 through R5.4 clearly
define the necessary level of analysis required by the RAS‐
owner. Leaving this phrase in will lead to confusion over whether the
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proper operation of a “composite” RAS is considered a deficiency if one
of the two redundant RAS suffer a component failure.
Response: Thank you for your comments.
The drafting team declines to make the suggested change. The drafting team contends that other NERC standards
provide adequate methods to assure data sharing among entities with a reliability need.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. When appropriate, new or
functionally modified RAS implemented after the effective date of this standard will be designated as limited impact
by the Reliability Coordinator during the RAS review process.
The drafting team regrets any confusion caused by the examples included in the supplemental material. The
supplemental material has been revised to better demonstrate the relationship between PRC‐005 component testing
and PRC‐012‐2 functional testing. The drafting team disagrees with the addition of functional testing to PRC‐005.
Requirement 8 in PRC‐012‐2 is only applicable to those non‐Protective System components used in RAS. The drafting
team contends these are the control components, such as programmable logic controllers, that have no applicability
within PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through component
testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005. The drafting
team chose functional testing to emphasize the logic and control functions of RAS and contends that functional
testing of the non‐Protection System RAS components in PRC‐012‐2 complements the component testing of PRC‐
005. The drafting team revised the standard to allow RAS that have limited impact to have functional testing
intervals of up to twelve full calendar years. However, the drafting team contends that the six full calendar year
interval is appropriate for the higher impact RAS given the potential negative impact to BES reliability should a RAS
operate incorrectly. Existing regional practices include more frequent RAS functional testing than the proposed six
full calendar year interval.
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Requirements R5.1.1 through 5.1.4 (R5.1 through R5.4 in the previously posted draft of PRC‐012‐2) state the scope of
the RAS operational performance, and therefore any “deficiencies” identified and reported to the RC per
Requirement R5.2 are with respect to these. The drafting team contends that if the RAS appropriately triggers for the
system conditions for which it was designed, and provides the desired response as designed, that a component
failure in one of two redundant RAS would not constitute a deficiency with respect to the operational analysis
described in Requirement R5. It would be expected, however, that if such a component failure was identified, the
RAS‐entity would be incented to repair the failed component as soon as possible to avoid the risk of the RAS failing to
operate for a future event. The drafting team declines to make the suggested change.
Richard Vine ‐ California ISO ‐ 2 ‐
Answer Comment:
The California ISO supports the comments of the ISO/RTO Standards
Review Committee
Response: Please see the drafting team’s responses to the referenced comments.
Jamison Cawley ‐ Nebraska Public Power District ‐ 1 ‐
Answer Comment:
The second version of PRC‐005 was intended to include all testing and
maintenance requirements from PRC‐017, and facilitate the retirement
of PRC‐017. Requirement 8 of the current draft of this standard (PRC‐
012‐2) includes testing and maintenance requirements related to those
found in PRC‐017‐0. Additionally, Requirement 8 of PRC‐012‐2 expands
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303
on those found in PRC‐017‐0 by including non‐Protection System
components. We feel this requirement should not be included in PRC‐
012‐2, and we request a clear description of the differences of the
intended purpose of the proposed PRC‐012‐2 Requirement 8 and that
of PRC‐017‐0/PRC‐005‐2. Furthermore, the remaining requirements of
PRC‐012‐2 seem to be primarily focused on system planning, and
consideration should be given to moving these to the TPL standard
family.
Response: Thank you for your comments.
The functional testing of a RAS to verify its performance is different from the maintenance activities associated with
the Protection System Components as detailed in the tables of PRC‐005. Requirement 8 of PRC‐012‐2 is only
applicable to those non‐Protective System components used in RAS. The drafting team contends these are the
control components, such as programmable logic controllers and are not Protection System Components and as
such, do not belong in PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through
component testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005.
The drafting team chose functional testing to emphasize the logic and control functions of RAS. The drafting team
contends that functional testing of the non‐Protection System RAS components in PRC‐012‐2 complements the
component testing of PRC‐005.
The work performed by the drafting team is in response to the SPCS/SAMS report “Special Protection Systems (SPS)
and Remedial Action Schemes (RAS): Assessment of Definition, Regional Practices, and Application of Related
Standards”. This report recommends “Project 2010‐05.2 should consolidate the requirements pertaining to review,
assessment, and documentation of SPS into one standard that includes continent‐wide procedures for reviewing new
or modified SPS, for assessing existing SPS in annual transmission planning assessments, and for periodic
comprehensive SPS assessments. The project also should revise requirements pertaining to analysis and reporting of
SPS misoperations in a revision of standard PRC‐016‐0.1.” The resulting SAR for aligns with this recommendation and
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would require the Standard process to re‐start with a new SAR. The drafting team maintains this is not necessary and
the Reliability objective of the SPCS/SAMS report can be met with PRC‐012‐2.
Likes:
Dislikes:
1
Nebraska Public Power District, 3, Eddleman Tony
0
Andrew Gallo ‐ Austin Energy ‐ 6 ‐
Answer Comment:
City of Austin dba Austin Energy suggests the SDT add clarifying
language to R8 to account for a RAS‐owner who owns only part of a
RAS. In doing so, the SDT may need to consider how a partial RAS‐
owner will be able “to verify the overall RAS performance.”
Response: Thank you for your comment.
The drafting team consolidated the former terms RAS‐entity and RAS‐owner in the Applicability section, revised the
requirements and Supplemental Material section of the standard to address these comments. The drafting team
revised the requirement to state that each RAS‐entity shall participate in the testing in order to assure accountability
for proper testing of each RAS. As explained in the Technical Justification, each separate RAS‐entity is obligated to
participate in various activities, as identified by the Requirements to the extent of their ownership. It is not the intent
of the drafting team, however, to specify how the RAS‐entities participate.
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Dixie Wells ‐ Lower Colorado River Authority ‐ 5 ‐
Group Name:
LCRA Compliance
Group Member Name
Entity
Regio Segme
n
nts
Michael Shaw
LCRA
TRE
6
Teresa Cantwell
LCRA
TRE
1
Dixie Wells
LCRA
TRE
5
Answer Comment:
To address existing entity NERC registration in the ERCOT region,
“Transmission Planner” should be replaced with “Transmission Planner
(in the ERCOT Region this applies to the Planning Authority and /or
Reliability Coordinator.)”
R4. Each Transmission Planner (in the ERCOT Region this applies to the
Planning Authority and /or Reliability Coordinator) shall perform an
evaluation of each RAS within its planning area at least once every 60‐
full‐calendar‐months and provide the RAS‐owner(s) and the reviewing
Reliability Coordinator(s) the results including any identified
deficiencies. Each evaluation shall determine whether: [Violation Risk
Factor: Medium] [Time Horizon: Long‐term Planning]
Response: Thank you for your comments.
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The drafting team revised the requirement. The Planning Coordinator (PC) is now the entity responsible for the
evaluation required per Requirement R4 and is required to provide the results of the RAS evaluation to each
reviewing Reliability Coordinator and each impacted Transmission Planner and RAS‐entity. The PC is the functional
entity best‐suited to perform this evaluation because they have a wide‐area planning perspective.
Tony Eddleman ‐ Nebraska Public Power District ‐ 3 ‐
Answer Comment:
The second version of PRC‐005 was intended to include all testing and
maintenance requirements from PRC‐017, and facilitate the retirement
of PRC‐017. Requirement 8 of the current draft of this standard (PRC‐
012‐2) includes testing and maintenance requirements related to those
found in PRC‐017‐0. Additionally, Requirement 8 of PRC‐012‐2 expands
on those found in PRC‐017‐0 by including non‐Protection System
components. We feel this requirement should not be included in PRC‐
012‐2, and we request a clear description of the differences of the
intended purpose of the proposed PRC‐012‐2 Requirement 8 and that
of PRC‐017‐0/PRC‐005‐2. Furthermore, the remaining requirements of
PRC‐012‐2 seem to be primarily focused on system planning, and
consideration should be given to moving these to the TPL standard
family.
Response: Thank you for your comments.
The functional testing of a RAS to verify its performance is different from the maintenance activities associated with
the Protection System Components as detailed in the tables of PRC‐005. Requirement 8 of PRC‐012‐2 is only
applicable to those non‐Protective System components used in RAS. The drafting team contends these are the
control components, such as programmable logic controllers and are not Protection System Components and as
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such, do not belong in PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through
component testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005.
The drafting team chose functional testing to emphasize the logic and control functions of RAS. The drafting team
contends that functional testing of the non‐Protection System RAS components in PRC‐012‐2 complements the
component testing of PRC‐005.
Likes:
Dislikes:
1
Nebraska Public Power District, 1, Cawley Jamison
0
Don Schmit ‐ Nebraska Public Power District ‐ 5 ‐
Answer Comment:
The second version of PRC‐005 was intended to include all testing and
maintenance requirements from PRC‐017, and facilitate the retirement
of PRC‐017. Requirement 8 of the current draft of this standard (PRC‐
012‐2) includes testing and maintenance requirements related to those
found in PRC‐017‐0. Additionally, Requirement 8 of PRC‐012‐2 expands
on those found in PRC‐017‐0 by including non‐Protection System
components. We feel this requirement should not be included in PRC‐
012‐2, and we request a clear description of the differences of the
intended purpose of the proposed PRC‐012‐2 Requirement 8 and that
of PRC‐017‐0/PRC‐005‐2. Furthermore, the remaining requirements of
PRC‐012‐2 seem to be primarily focused on system planning, and
consideration should be given to moving these to the TPL standard
family.
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Response: Thank you for your comments.
The functional testing of a RAS to verify its performance is different from the maintenance activities associated with
the Protection System Components as detailed in the tables of PRC‐005. Requirement 8 of PRC‐012‐2 is only
applicable to those non‐Protective System components used in RAS. The drafting team contends these are the
control components, such as programmable logic controllers and are not Protection System Components and as
such, do not belong in PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through
component testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005. The
drafting team chose functional testing to emphasize the logic and control functions of RAS. The drafting team
contends that functional testing of the non‐Protection System RAS components in PRC‐012‐2 complements the
component testing of PRC‐005.
Likes:
Dislikes:
1
Nebraska Public Power District, 1, Cawley Jamison
0
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10 ‐
Answer Comment:
Texas RE seeks clarification on the following:
• If a RAS is implemented to run‐back a generator due to a line loading
trigger level, is the Generator Owner a RAS‐owner by default? Or is it
dependent upon the ownership of the components that are used (e.g.,
protective or auxiliary relays, communication systems, sensing devices,
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station DC, control circuitry, etc.)?
• In Requirement R5, is the responsibility associated with the each
RAS‐owner correct? Should that responsibility be the RAS‐entity (in
collaboration with all RAS‐owners) to avoid multiple analysis activities
which may result in conflicting results and/or CAPs? If one RAS‐owner
finds a deficiency in another owner’s portion of the RAS, how is that
notification made?
• In Requirement R5 there is no notification of a deficiency to a RAS‐
owner. Is notification considered to be when a RAS‐owner recognizes a
deficiency in its part of the RAS? R6 references a notification but it is
not clear in R5.
• Does the SDT consider “arming”, whether it signals another party to
act or is used in situational awareness, as an integral part of RAS
operation? Some RAS designs include an “arming” phase (e.g., A RAS
will “arm” if the amperage on line X measure 900 amps. If the
amperage measures 920 amps the RAS will activate. In some designs,
“arming” may signal action to be taken by another party is needed (e.g.
generator runback to level X), and if the action is not taken the RAS may
fully activate (e.g. trip generator).) In the Supplemental Material (and
somewhat, but not totally, mirrored in the rationale for R5) there is the
statement: “A RAS operational performance analysis is intended to: (1)
verify RAS operation is consistent with implemented design; or (2)
identify RAS performance deficiency(ies) that manifested in the
incorrect RAS operation or failure of RAS to operate when
expected.” Failure of a RAS to arm, if designed to arm, is indicative that
the design was improperly implemented.
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• In Requirement R8, which entity responsible for coordinating the
functional test for a multi‐owner RAS that covers a wide area? The
segmented approach referred to in the rationale may cover an
individual RAS‐owner’s trip function or communications, but there
needs to be an overall functional test of the logic that
arms/disarms/activates the RAS, which may involve multiple RAS‐
owners. Texas RE recommends changing the requirement language to
“RAS‐owner, or RAS‐entity as mutually agreed by the RAS‐owners
shall…”. Also, a functional test should be required if there is a system
change that affects one or more Elements that are monitored or
operated as part of a RAS, in order to verify any logic
changes. Requirements R1‐R3 currently do not address functional
testing, only the design. Texas RE recommends R8 indicate “proper
operation of RAS” elements and not limit the functional test verification
to non‐Protection System components. Some Protection System
components involved in the proper operation of a RAS may have an
extended maintenance intervals and the RAS would not be functionally
tested without including Protection System components. Overall RAS
performance cannot be attained without functionally testing all aspects
of the RAS.
Texas RE noticed an inconsistency between the requirement language
and the RSAW. The requirement language of Requirement R5 states
“Each RAS‐owner shall” but the Note to Auditor in the Requirement R5
section of the RSAW indicates that a RAS‐entity can provide the
analysis. Registered entities are held accountable to the language of
the requirement. Introducing the concept of a RAS‐entity providing the
information adds confusion. If the intent is for both the RAS‐Owner and
the RAS‐entity to be able to analyze RAS performance and provide the
results, Texas RE recommends changing the requirement language to
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“RAS‐owner, or RAS‐entity as mutually agreed by the RAS‐owners
analyze…”. Texas RE supports the idea of a RAS‐entity doing the
analysis.
Additionally, Texas RE recommends a requirement to report the
degraded RAS to the RC. Texas RE noticed the referenced
Standards/Requirements (i.e., Supplemental Material indicates PRC‐001
R6 and TOP‐001‐2 R5) are either being retired or are not explicit enough
to ensure that the reliability of the system is maintained for those who
should have situational awareness. This is a perceived gap due to the
current steady state of the standards.
Texas RE recommends Attachment 3 include the RAS‐owner(s) as well
as the RAS‐entity. If Requirement R9 is left as “at a minimum”, that is
all that will be done. Ownership is critical to know because of the
responsibilities required in the majority of the Requirements (e.g., How
will the TP provide results to owners without knowing all the owners?)
The TP does not, generally, know the RAS‐owners based on the
ownership at the component level.
Response: Thank you for your comments.
The drafting team maintains that the owner of the components in the scenario you describe; e.g., the generator
control system would be an owner of the RAS; i.e., a RAS‐entity.
The drafting team revised the standard such that Requirement R5 applies to the RAS‐entity. The drafting team
consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the Transmission Owner,
Generator Owner, or Distribution Provider that owns all or part of a RAS. As explained in the Technical Justification,
each separate RAS‐entity is obligated to participate in various activities, as identified by the Requirements to the
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extent of their ownership. It is not the intent of the drafting team, however, to specify how the RAS‐entities
participate.
The drafting team revised Requirements R5 and R6.
The drafting team contends that failure of a RAS to arm, if designed to arm, may be indicative that the design was
improperly implemented or the RAS did not operate as designed. The event would be handled as a failure to operate,
since RAS action should not occur without prior arming, and a CAP developed to resolve the issue pursuant to R6.
Any incorrect operation of a RAS, in whole or in part, indicates that the RAS effectiveness and/or coordination has
been compromised. The correct operation of a RAS is important for maintaining the reliability and integrity of the
BES.
The drafting team revised the requirement to state that each RAS‐entity shall participate in the testing in order to
assure accountability for proper testing of each RAS. As explained in the Technical Justification, each separate RAS‐
entity is obligated to participate in various activities, as identified by the Requirements to the extent of their
ownership. It is not the intent of the drafting team, however, to specify how the RAS‐entities participate. Attachment
1 includes item III. 5 to describe the functional testing process.
The drafting team contends that each owner of a RAS or part of a RAS is a RAS‐entity which is responsible for
compliance with the requirements of PRC‐012. It is not the intent of the drafting team to specify how multiple RAS
owners will coordinate. The drafting team believes that it is in the best interest of the BES and the entity to perform
a commissioning test, likely to include functional testing when there is a required system change that affects one or
more Elements of RAS. The drafting team doesn’t dispute the value of functional testing following System changes or
RAS logic changes but the standard does not address “commissioning” testing of these changes and contends that is
good utility practice but declines to include this in the standard and that adding an additional requirement is
unnecessary. The drafting team declines to add an addition requirement to mandate functional testing during RAS
changes make the suggested change. The drafting team contends that a “functional test of each RAS to verify the
overall RAS performance”, as specified in Requirement R8 would include testing of the entire RAS. Requirement R8
specifically requires testing proper operation only of non‐Protection System components because Protection System
components installed as part of a RAS are already addressed by PRC‐005‐5.
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The drafting team added language to the measure for Requirement 8 indicating that a correct operation of a RAS
segment would qualify as a functional test. In addition, the team will include that in the RSAW for PRC‐012,
Requirement R8. The drafting team’s consolidation of RAS‐owner and RAS‐entity into the single RAS‐entity should
answer the concern regarding which entity analyzes and reports on RAS operational failures.
The status of a degraded RAS is required to be reported (in Real‐time) to the Transmission Operator via PRC‐001,
Requirement R6, then to the RC via TOP‐001‐3, Requirement R8. See Phase 2 of Project 2007‐06 for the mapping
document from PRC‐001 to other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
The drafting team consolidated the former terms RAS‐entity and RAS‐owner in the Applicability section, revised the
requirements and Supplemental Material section of the standard to address these comments.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1 ‐
Answer Comment:
∙ Hydro One Networks Inc. recommends that the standard should
recognize that all RASs are not equal and therefore, should not be
subject to the same level of design review (as per R1), performance
requirements in case of RAS failure (as per 4.4), and operation analysis
(as per R5). We suggest defining two or more “class” or “type” for RAS
based on the impact of their misoperation or failure to operate on the
system performance. Different classes or types of RAS will
consequently have different levels of design, performance and analysis
requirements associated with them. Hydro One Networks Inc. would
like to emphasize that in the absence of a means of differentiation (via
typing or classes of RAS), utilities will feel compelled to spend significant
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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314
capital, for little or no material improvement to system reliability.
∙ Hydro One Networks Inc. believes that requirement R8 and
guidance provided in the supplemental material appear to overstep the
direction provided by the SAR, which states that the standard will
address maintenance and testing on non‐Protection System
components of a RAS. Maintenance of Protection Systems installed as
a RAS for BES reliability is clearly covered in PRC‐005. Hydro One
Networks Inc. further joins the NPCC with its concern over the different
timeframes provided and duplicative testing for RAS components. In
particular, the supplemental material provided is very confusing and
appears to suggest duplicative testing compared to testing already
required in PRC‐005. Hydro One Networks Inc. agrees with the NPCC
and suggests that all testing requirements for RAS should be contained
in one standard. NERC PRC‐005 applies to Protection Systems installed
as Remedial Action Schemes for BES reliability. As such, all RAS
Protective Relays, Communication Systems, Voltage and Current
Sensing Devices Providing Inputs to Protective Relays, Control Circuitry,
DC Supply, alarms and Automatic Reclosing Components are already
included in PRC‐005. Lastly, this requirement would force entities to
perform testing on local area schemes; yet non‐BES components are
not subject to maintenance requirements under NERC PRC‐005. Typing
would be a good mythology to distinguish which RAS schemes should
be subject to the strict maintenance requirements.
∙ Hydro One Networks Inc. also agrees with the NPCC in suggesting
the deletion of the phase “including any identified deficiencies” in R5
because requirements R5.1 through R5.4 clearly define the necessary
level of analysis required by the RAS‐owner. Leaving this phrase in
would lead to confusion over whether the proper operation of a
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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315
“composite” RAS is considered a deficiency if one of the two redundant
RAS suffer a component failure.
Response: Thank you for your comments.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. When appropriate, new or
functionally modified RAS implemented after the effective date of this standard will be designated as limited impact
by the Reliability Coordinator during the RAS review process.
The functional testing of a RAS to verify its performance is different from the maintenance activities associated with
the Protection System Components as detailed in the tables of PRC‐005. Requirement 8 of PRC‐012‐2 is only
applicable to those non‐Protective System components used in RAS. The drafting team contends these are the
control components, such as programmable logic controllers and are not Protection System Components and as
such, do not belong in PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through
component testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005. The
drafting team chose functional testing to emphasize the logic and control functions of RAS. The drafting team
contends that functional testing of the non‐Protection System RAS components in PRC‐012‐2 complements the
component testing of PRC‐005.
The drafting team included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. When appropriate, new or
functionally modified RAS implemented after the effective date of this standard will be designated as limited impact
by the Reliability Coordinator during the RAS review process. Limited impact schemes have a twelve full calendar
year functional test interval in Requirement R8.
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316
The drafting team regrets any confusion caused by the examples included in the supplemental material. The
supplemental material has been revised to better demonstrate the relationship between PRC‐005 component testing
and PRC‐012‐2 functional testing. The drafting team disagrees with the addition of functional testing to PRC‐005.
Requirement 8 in PRC‐012‐2 is only applicable to those non‐Protective System components used in RAS. The drafting
team contends these are the control components, such as programmable logic controllers, that have no applicability
within PRC‐005. The Protection System definition used within PRC‐005 ensures BES reliability through component
testing to verify each component’s ability to operate. Functional testing is not an activity in PRC‐005. The drafting
team chose functional testing to emphasize the logic and control functions of RAS and contends that functional
testing of the non‐Protection System RAS components in PRC‐012‐2 complements the component testing of PRC‐
005. The drafting team revised the standard to allow RAS that have limited impact to have functional testing intervals
of up to twelve full calendar years. However, the drafting team contends that the six full calendar year interval is
appropriate for the higher impact RAS given the potential negative impact to BES reliability should a RAS operate
incorrectly. Existing regional practices include more frequent RAS functional testing than the proposed six full
calendar year interval.
Requirements R5.1.1 through 5.1.4 (R5.1 through R5.4 in the previously posted draft of PRC‐012‐2) state the scope of
the RAS operational performance, and therefore any “deficiencies” identified and reported to the RC per
Requirement R5.2 are with respect to these. The drafting team contends that if the RAS appropriately triggers for the
system conditions for which it was designed, and provides the desired response as designed, that a component
failure in one of two redundant RAS would not constitute a deficiency with respect to the operational analysis
described in Requirement R5. It would be expected, however, that if such a component failure was identified, the
RAS‐entity would be incented to repair the failed component as soon as possible to avoid the risk of the RAS failing to
operate for a future event. The drafting team declines to make the suggested change.
Carol Chinn ‐ Florida Municipal Power Agency ‐ 4 ‐
Group Name:
FMPA
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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317
Group Member Name
Entity
Regio
n
Tim Beyrle
City of New Smyrna Beach
FRCC
Jim Howard
Lakeland Electric
FRCC
Lynne Mila
City of Clewiston
FRCC
Javier Cisneros
Fort Pierce Utility Authority
FRCC
Randy Hahn
Ocala Utility Services
FRCC
Don Cuevas
Beaches Energy Services
FRCC
Stan Rzad
Keys Energy Services
FRCC
Matt Culverhouse
City of Bartow
FRCC
Tom Reedy
Florida Municipal Power Pool
FRCC
Steven Lancaster
Beaches Energy Services
FRCC
Mike Blough
Kissimmee Utility Authority
FRCC
Mark Brown
City of Winter Park
FRCC
Mace Hunter
Lakeland Electric
FRCC
Segme
nts
4
3
3
4
3
1
4
3
6
3
5
3
3
Answer Comment:
The roles and relationships between the RAS‐entity and the RAS‐owners
could be made clearer throughout the standard. Overall, FMPA
supports the drafting team’s approach, but there have been several
comments submitted that should be considered before the standard is
approved and would like to see outreach done before the next posting
of the standard for comment and ballot.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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318
Response: Thank you for your comments.
The drafting team consolidated the terms RAS‐owner and RAS‐entity. The term RAS‐entity is now defined as the
Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable
Group Name:
ACES Standards Collaborators
Group Member Name
Entity
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
Ginger Mercier
Prairie Power, Inc.
Ellen Watkins
Sunflower Electric Power
Corporation
Michael Brytowski
Great River Energy
Shari Heino
Brazos Electric Power Cooperative,
Inc.
John Shaver
Arizona Electric Power
Cooperative, Inc.
John Shaver
Southwest Transmission
Cooperative, Inc.
Regio
n
RFC
Segme
nts
1
SERC
1,3
SPP
1
MRO
1,3,5,6
TRE
1,5
WECC 4,5
WECC 1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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319
Answer Comment:
(1) Requirement R9 requires the RC to update its RAS database
annually. However, we believe the requirement should be rewritten to
require the RC to develop and implement a process to conduct a review
of its database and at what frequency. If a RAS‐owner has not made
any changes to functionality and system conditions and operating
configurations are as expected, we feel this requirement is more of an
administrative burden falling under Paragraph 81 Data Collection
criteria.
(2) We question how a RC is expected to maintain a dated revision
history as evidence for Requirement R9 when the context of this
requirement is to update a database. We believe the requirement is
more of an administrative burden falling under Paragraph 81 Data
Collection criteria, and the requirement should be rewritten to require
the RC to develop and implement a process to conduct a review of its
database and at what frequency.
(3) We believe the evidence retention of this standard should identify
retention periods for applicable entities and not limit retention just for
TOs, GOs, and DPs.
(4) The VSLs for Requirements R1 and R3 currently have only a Severe
VSL identified. We believe the VSL criteria for these requirements could
be written on a sliding time scale based on the projected installation or
retirement dates of a RAS.
(5) We believe the VSL criteria listed with many requirements is too
condensed. We recommend incrementing the criteria for Requirement
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2
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320
R4 by quarters instead of by months. Moreover, we recommend
incrementing the criteria for Requirement R5 by months rather than by
every ten days. We also recommend incrementing the criteria for
Requirements R8 and R9 by quarters rather every thirty days.
(6) We have concerns that the SDT has introduced a new measure of
time, the “full‐calendar‐month.” This measure will cause confusion
with implementation and during audits. Moreover, there is inconsistent
uses of this time measure within the standard. The SDT uses 60‐full‐
calendar‐months in R4, but does not use the same measurement in R5
for 120‐calendar days and R8 for six‐calendar years. Should R5 be four‐
full‐calendar‐months and R8 be six‐full‐calendar‐years? The rationale
for “full‐calendar months” is only specified within the RSAW of this
Standard. We feel the SDT should remove the measure of “full‐calendar
months” and replace it with “calendar months” to be consistent with
the other NERC standards.
(7) We thank you for this opportunity to comment on this standard.
Response: Thank you for your comments.
The drafting disagrees that updating a RAS database is an administrative requirement because the database serves as
a reliability resource in that the RC can provide other entities high‐level information from the database on existing
RAS that could potentially impact the operational and/or planning activities of those entities. Readily available
software tools allow easy and automatic application of revision dates to documents when updating database
documents. Requirement R9 mandates an update frequency of at least every 12 full calendar months.
The drafting team revised the Compliance section of the standard to address this.
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321
The drafting team does not agree that the VSL criteria for Requirements R1 and R3 should be written on a sliding
time scale based on the projected installation or retirement dates of a RAS. Projected installation dates are not
relevant to the reliability issues. The relevant issue, for both requirements, is to complete a review of the RAS prior
to placing a new or functionally modified RAS in‐service.
The drafting team declines to make the suggested change to the VSLs.
The drafting team notes that, e.g. PRC‐026‐1 also uses “full calendar months” terminology. The drafting team
declines to make the suggested change.
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer Comment:
BPA believes R5’s reporting to the RC of the correct operation of a RAS
is unduly onerous without providing value. BPA analyzes all RAS
operations. If we see a scheme that operates too frequently (this is
very subjective), we evaluate that scheme to see if there is something
that can be done to minimize the number of operations. BPA proposes
this be deleted from the requirement.
Response: Thank you for your comment.
The drafting team has modified Requirement R5 to only require reporting of the results of RAS operational analyses
when there was an incorrect operation or failure to operate; correct operations do not need to be reported.
End of report
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322
PRC‐012‐2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 2 of PRC‐012‐2 corrects the applicability of the fill‐in‐the‐blank standards (PRC‐012‐1,
PRC‐013‐1, and PRC‐014‐1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk‐Power System, and incorporates the reliability objectives of
all the RAS/SPS‐related standards. This draft contains nine requirements and measures, the
associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. This draft of PRC‐012‐2 is posted for a 45‐day formal comment period with a
parallel ballot in the last ten days of the comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC‐012‐2 posted for informal comment
April 30 – May 20, 2015
45‐day formal comment period with initial ballot
August 20 – October 5,
2015
45‐day formal comment period with additional ballot
November 25, 2015 –
January 8, 2016
Anticipated Actions
Date
10‐day final ballot
March 2016
NERC Board (Board) adoption
May 2016
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
3.
Number:
Purpose:
PRC‐012‐2
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Planning Coordinator
4.1.3. RAS‐entity – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC‐012‐2.
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement; i.e., removal from service must be completed prior
to implementation or retirement.
Functional modifications consist of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement of existing components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS‐entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS‐entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. Ideally, when there is more than one RAS‐entity for
a RAS, the RAS‐entities would collaborate and submit a single, coordinated Attachment 1
to the reviewing RC. In cases where a RAS crosses one or more RC Area boundaries, each
affected RC is responsible for conducting either individual reviews or participating in a
coordinated review.
R1.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest‐area operational and reliability perspective of all
functional entities and an awareness of reliability issues in any neighboring RC Area. This
Wide Area purview facilitates the evaluation of interactions among separate RAS as well
as interactions among RAS and other protection and control systems. Review by the RC
also minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP),
or other entities that are likely to be involved in the planning or implementation of a RAS.
The RC is not expected to possess more information or ability than anticipated by their
functional registration as designated by NERC. The RC may request assistance to perform
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
RAS reviews from other parties such as the PC or regional technical groups; however, the
RC will retain the responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each submitted RAS.
The time frame of four full calendar months is consistent with current utility and regional
practice; however, flexibility is provided by allowing the RC(s) and RAS‐entity(ies) to
negotiate a mutually agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to each RAS‐entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS‐entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in‐service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS‐entity to respond to the reviewing RC following
identification of any reliability issue(s) is not necessary because the RAS‐entity wants to
expedite the timely approval and subsequent implementation of the RAS.
R3.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability Coordinator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every sixty full calendar months. The purpose of the periodic
RAS evaluation is to verify the continued effectiveness and coordination of the RAS, as
well as to verify that, if a RAS single component failure or single component malfunction
were to occur, the requirements for BES performance would continue to be satisfied. The
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
periodic evaluation is needed because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it impacts the BES.
Requirement R4 also clarifies that the RAS single component failure and single
component malfunction tests do not apply to RAS which are determined to be limited
impact. A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented after the effective date of this standard will be designated as limited
impact or not by the reviewing RC(s) during its review. A RAS implemented prior to the
effective date of this standard that has been through the regional review process and
designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4. Requiring a
limited impact RAS to meet the single component failure and single component
malfunction tests would add complexity to the design with minimal benefit to the
reliability of the BES. See Attachment 2 for a description of the limited impact
determination by the Reliability Coordinator.
For existing RAS, the initial performance of Requirement R4 must be completed within
sixty full calendar months of the effective date of PRC‐012‐2. For new or functionally
modified RAS, the initial performance of the requirement must be completed within sixty
full calendar months of the RAS approval date by the reviewing RC(s). Sixty full calendar
months was selected as the maximum time frame between evaluations based on the time
frames for similar requirements in Reliability Standards PRC‐006, PRC‐010, and PRC‐014.
The RAS evaluation can be performed sooner if it is determined that material changes to
System topology or System operating conditions could potentially impact the
effectiveness or coordination of the RAS. The periodic RAS evaluation will typically lead to
one of the following outcomes: 1) affirmation that the existing RAS is effective; 2)
identification of changes needed to the existing RAS; or, 3) justification for RAS
retirement.
The items required to be addressed in the evaluation may involve modeling of the
interconnected transmission system to assess BES performance. The Planning
Coordinator (PC) is the functional entity best suited to perform this evaluation because
they have a wide area planning perspective. To promote reliability, the PC is required to
provide the results of the evaluation to each impacted Transmission Planner and Planning
Coordinator, in addition to each reviewing RC and RAS‐entity.
The previous version of this standard (PRC‐012‐1 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL‐001‐
0, TPL‐002‐0, and TPL‐003‐0) as that required of the Contingency for which it was
designed, and not exceed TPL‐003‐0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise,
consistent with PRC‐012‐1 Requirement 1, R1.4, the RAS should be designed so that its
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
whole or partial inadvertent operation due to a single component malfunction satisfies
the System performance requirements for the same Contingency for which the RAS was
designed.
If the RAS was installed for an extreme event in TPL‐001‐4 or for some other Contingency
or System condition not defined in TPL‐001‐4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL‐001‐4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.1.3.1 – 4.1.3.5) are the ones that
are common to all planning events P0‐P7 listed in TPL‐001‐4.
R4.
Each Planning Coordinator, at least once every 60 full calendar months, shall:
[Violation Risk Factor: Medium] [Time Horizon: Long‐term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for which
it was designed.
4.1.2. The RAS avoids adverse interactions with other RAS, and protection and
control systems.
4.1.3. Except for “limited impact”1 RAS, the possible inadvertent operation of
the RAS, resulting from any single RAS component malfunction satisfies
all of the following:
4.1.3.1.
The BES shall remain stable.
4.1.3.2.
Cascading shall not occur.
4.1.3.3.
Applicable Facility Ratings shall not be exceeded.
4.1.3.4.
BES voltages shall be within post‐Contingency voltage limits
and post‐Contingency voltage deviation limits as established
by the Transmission Planner and the Planning Coordinator.
4.1.3.5.
Transient voltage responses shall be within acceptable limits
as established by the Transmission Planner and the Planning
Coordinator.
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4.
1
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
4.1.4. Except for limited impact RAS, a single component failure in the RAS,
when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS‐entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS‐entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation was
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4
regarding the investigation of a Protection System Misoperation. To promote reliability,
each RAS‐entity is required to provide the results of RAS operational performance
analyses that identified any deficiencies to its reviewing RC(s).
RAS‐entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly
(Part 5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response
(Parts 5.1.3 and 5.1.4) was consistent with the intended functionality and design of the
RAS. Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would
collaborate on the operational performance analysis.
R5.
Each RAS‐entity, within 120 full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
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PRC‐012‐2 – Remedial Action Schemes
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.1. The System events and/or conditions appropriately triggered the RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with the reviewing Reliability Coordinator(s) in accordance with Requirement R5.
Rationale for Requirement R6: Deficiencies identified in the periodic RAS evaluation
conducted by the PC pursuant to Requirement R4, in the operational performance
analysis conducted by the RAS‐entity pursuant to Requirement R5, or in the functional
test performed by the RAS‐entity pursuant to Requirement R8, potentially pose a
reliability risk to the BES. To mitigate these potential reliability risks, Requirement R6
mandates that each RAS‐entity develop a Corrective Action Plan (CAP) to address the
identified deficiency. The CAP contains the mitigation actions and associated timetable
necessary to remedy the specific deficiency. The RAS‐entity may request assistance with
CAP development from other parties such as its Transmission Planner or Planning
Coordinator; however, the RAS‐entity has the responsibility for compliance with this
requirement.
If the CAP requires that a functional change be made to a RAS, the RAS‐entity will need to
submit information identified in Attachment 1 to the reviewing RC(s) prior to placing RAS
modifications in‐service per Requirement R1.
Depending on the complexity of the identified deficiency(ies), development of a CAP may
require studies, and other engineering or consulting work. A maximum time frame of six
full calendar months is specified for RAS‐entity collaboration on the CAP development.
R6.
Each RAS‐entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐
term Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator pursuant to Requirements R5, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
Draft 2 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS‐entity in
accordance with Requirement R6.
Rationale for Requirement R7: Requirement R7 mandates each RAS‐entity implement a
CAP (developed in Requirement R6) that mitigates the deficiencies identified in
Requirements R4, R5, or R8. By definition, a CAP is: “A list of actions and an associated
timetable for implementation to remedy a specific problem.” The implementation of a
properly developed CAP ensures that RAS deficiencies are mitigated in a timely manner.
Each reviewing Reliability Coordinator must be notified if CAP actions or timetables
change, and when the CAP is completed.
R7.
Each RAS‐entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the reviewing Reliability
Coordinator(s) that documents the implementation, updating, or completion of a CAP
in accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non‐Protection System (control) components of a RAS that are not addressed in PRC‐005.
Protection System components that are part of a RAS are maintained in accordance with
PRC‐005.
The six or twelve full calendar year test interval, which begins on the effective date of the
standard pursuant to the PRC‐012‐2 implementation plan, is a balance between the
resources required to perform the testing and the potential reliability impacts to the BES
created by undiscovered latent failures that could cause an incorrect operation of the
RAS. Extending to longer intervals increases the reliability risk to the BES posed by an
undiscovered latent failure that could cause an incorrect operation or failure of the RAS.
The RAS‐entity is in the best position to determine the testing procedure and schedule
due to its overall knowledge of the RAS design, installation, and functionality. Functional
testing may be accomplished with end‐to‐end testing or a segmented approach. For
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
segmented testing, each segment of a RAS must be tested. Overlapping segments can be
tested individually negating the need for complex maintenance schedules and outages.
The maximum allowable interval between functional tests is six full calendar years for RAS
that are not designated as limited impact RAS and twelve full calendar years for RAS that
are designated as limited impact RAS. The interval between tests begins on the date of
the most recent successful test for each individual segment or end‐to‐end test. A
successful test of one segment only resets the test interval clock for that segment. A
correct operation of a RAS qualifies as a functional test for those RAS segments which
operate (documentation for compliance with Requirement R5 Part 5.1). If an event causes
a partial operation of a RAS, the segments without an operation will require a separate
functional test within the maximum interval with the starting date determined by the
previous successful test of the segments that did not operate.
R8.
Each RAS‐entity shall participate in performing a functional test of each of its RAS to
verify the overall RAS performance and the proper operation of non‐Protection
System components: [Violation Risk Factor: High] [Time Horizon: Long‐term Planning]
At least once every six full calendar years for all RAS not designated as limited
impact, or
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis for a correct RAS segment or an end‐to‐end
operation (Measure M5 documentation), or dated documentation demonstrating that
a functional test of each RAS segment or an end‐to‐end test was performed in
accordance with Requirement R8.
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high‐level information on existing RAS that could potentially impact the
operational and/or planning activities of that entity. Attachment 3 lists the minimum
information required for the RAS database, which includes a summary of the RAS
initiating conditions, corrective actions, and System issues being mitigated. This
information allows an entity to evaluate the reliability need for requesting more detailed
information from the RAS‐entities identified in the database contact information. The RC
is the appropriate entity to maintain the database because the RC receives the required
database information when a new or modified RAS is submitted for review. The twelve
full calendar month time frame is aligned with industry practice and allows sufficient time
for the RC to collect the appropriate information from RAS‐entities and update the RAS
database.
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November 2015
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PRC‐012‐2 – Remedial Action Schemes
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS‐entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1, R3, R5, R6, R7, and R8, and Measures M1, M3, M5, M6, M7,
and M8 since the last audit, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M2 and M9 since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS‐entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non‐compliant, it shall
keep information related to the non‐compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
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November 2015
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PRC‐012‐2 – Remedial Action Schemes
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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November 2015
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PRC‐012‐2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS‐entity failed to
provide the information
identified in Attachment 1 to
each Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30 full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90 full
calendar days.
Draft 2 of PRC‐012‐2
November 2015
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
Page 13 of 46
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS‐entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
R4.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 60 full calendar
months but less than or
equal to 61 full calendar
months.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 61 full calendar
months but less than or
equal to 62 full‐calendar
months.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 62 full calendar
months but less than or
equal to 63 full calendar
months.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 63 full calendar
months.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate two or more of
the Parts 4.1.1 through 4.1.4.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1.1 through 4.1.4.
Draft 2 of PRC‐012‐2
November 2015
OR
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
R5.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by less than or
equal to 10 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 30 full
calendar days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to address two or
more of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to address one of the
Parts 5.1.1 through 5.1.4.
Draft 2 of PRC‐012‐2
November 2015
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
(Part 5.2) to one or more of
the reviewing Reliability
Coordinator(s).
OR
The RAS‐entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10 full calendar days.
Draft 2 of PRC‐012‐2
November 2015
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30 full
calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but
failed to submit it to one or
Page 16 of 46
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
more of its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6.
OR
The RAS‐entity failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS‐entity implemented N/A
a CAP in accordance with
Requirement R7, Part 7.1,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed, or failed
to notify (Part 7.3) each of
the reviewing Reliability
Coordinator(s) of the
updated CAP or completion
of the CAP.
N/A
The RAS‐entity failed to
implement a CAP in
accordance with
Requirement R7, Part 7.1.
R8.
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by less than
or equal to 30 full calendar
days.
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 60 full calendar days
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 90 full calendar days.
Draft 2 of PRC‐012‐2
November 2015
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 30 full calendar days
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
R9.
Moderate VSL
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30 full calendar days.
Draft 2 of PRC‐012‐2
November 2015
High VSL
Severe VSL
but less than or equal to 60
full calendar days.
but less than or equal to 90
full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
OR
The RAS‐entity failed to
perform the functional test
for a RAS as specified in
Requirement R8.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90 full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
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PRC‐012‐2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
Date
Action
Change Tracking
1
Adopted by NERC Board of Trustees
New
Draft 2 of PRC‐012‐2
November 2015
Page 19 of 46
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified2 RAS that the RAS‐entity must document and provide to
the reviewing Reliability Coordinator(s) (RC). If an item on this list does not apply to a
specific RAS, a response of “Not Applicable” for that item is appropriate. When RAS are
submitted for functional modification review and approval, only the proposed modifications
to that RAS require review; however, the RAS‐entity must provide a summary of the existing
functionality. The RC may request additional information on any aspect of the RAS as well as
any reliability issue related to the RAS. Additional entities (without decision authority) may
be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐
voltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
2
f. Action(s) to be taken by the RAS.
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement of existing components
•
Changes to RAS logic beyond error correcting
•
Changes to redundancy levels; i.e., addition or removal
Draft 2 of PRC‐012‐2
November 2015
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Attachments
g. Identification of limited impact3 RAS.
h. Any additional explanation relevant to high‐level understanding of the RAS.
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS‐entity proposed designation as limited impact or not.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
8. Identification of other affected RCs.
3
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact.
Draft 2 of PRC‐012‐2
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Attachments
III. Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, control actions, logic processing, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in‐service or is being
maintained.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective.
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS‐entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability‐related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any aspect of the RAS as well as any reliability issue related to the RAS. If a
checklist item is not relevant to a particular RAS, it should be noted as “Not Applicable.” If
reliability considerations are identified during the review, the considerations and the proposed
resolutions should be documented with the remaining applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
3. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
4. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate, have been identified.
5. Determination whether or not the RAS is “limited impact.5” A RAS designated as limited
impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations.
6. Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
4
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement of existing components
•
Changes to RAS logic beyond error correcting
•
Changes to redundancy levels; i.e., addition or removal
5
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
Draft 2 of PRC‐012‐2
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Attachments
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. The effects of future BES modifications on the design and operation of the RAS have
been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. The timing of RAS action(s) is appropriate to its BES performance objectives.
3. Except for limited impact RAS as determined by the RC, a single component failure in a
RAS does not prevent the BES from meeting the same performance requirements as
those required for the events and conditions for which the RAS is designed.
4. The RAS design facilitates periodic testing and maintenance.
5. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
Draft 2 of PRC‐012‐2
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Attachments
Attachment 3
Database Information
1. RAS name.
2. Each RAS‐entity and contact information.
3. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact6 RAS.
8. Any additional explanation relevant to high‐level understanding of the RAS.
6
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
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Technical Justifications for Requirements
Applicability
4.1.1 Reliability Coordinator
The Reliability Coordinator (RC) is the best‐suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest‐area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide‐
Area purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best‐suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS‐entity
The RAS‐entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RAS‐
entity has sole responsibility for all the activities assigned within the standard to the RAS‐entity.
If the RAS (RAS components) have more than one owner, then each separate RAS component
owner is a RAS‐entity and is obligated to participate in various activities identified by the
Requirements.
The standard does not stipulate particular compliance methods. RAS‐entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS‐entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS‐entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
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Functional modifications consists of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement of existing components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in‐kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that uses similar
functions. For instance, if a RAS included a CO‐11 relay which was replaced by an IAC‐53 relay,
that would be an in‐kind replacement. If the CO‐11 relay were replaced by a microprocessor
SEL‐451 relay that used only the same functions as the original CO‐11 relay, that would also be
an in‐kind replacement; however, if the SEL‐451 relay was used to add new logic to what the
CO‐11 relay had provided, then the replacement relay would be a functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. For example, System conditions require a RAS to be armed when the
combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to Requirement
R4, or other assessment, indicates that the arming level should be reduced to 450 MW without
requiring any other RAS changes that would not be a functional modification. Similarly, if a RAS
is designed to shed load to reduce loading on a particular line below 1000 amps, then a change
in the load shedding trigger from 1000 amps to 1100 amps would not be a functional
modification.
Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs to the RAS) and the logic to recognize the specific line outages would
change, while the generation reduction (RAS output) requirement may or may not change,
depending on which line is out of service. These required RAS changes would be a functional
modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for such functional modifications
may be identified in several ways including but not limited to the Planning evaluations pursuant
to R4, incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning
assessments related to future additions or modifications of other facilities.
To facilitate a review that promotes reliability, the RAS‐entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS‐entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
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coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS‐entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RAS‐
entity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS‐entity(ies). An independent review by a multi‐disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the
widest‐area reliability perspective of all functional entities and an awareness of reliability issues
in neighboring RC Areas. This Wide Area purview facilitates the evaluation of interactions
among separate RAS as well as interactions among the RAS and other protection and control
systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS‐entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement. It is recognized that the RC does not
possesses more information or ability than anticipated by their functional registration as
designated by NERC. The NERC Functional Model is a guideline for the development of
standards and their applicability and does not contain compliance requirements. If Reliability
Standards address functions that are not described in the model, the Reliability Standard
requirements take precedence over the Functional Model. For further reference, please see the
Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
for review. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
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schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
Requirement R3
Requirement R3 mandates that each RAS‐entity resolve all reliability issues (pertaining to its
RAS) identified during the RAS review by the reviewing Reliability Coordinators. Examples of
reliability issues include a lack of dependability, security, or coordination. RC approval of a RAS
is considered to be obtained when the reviewing RC’s feedback to each RAS‐entity indicates
that either no reliability issues were identified during the review or all identified reliability
issues were resolved to the RC’s satisfaction.
Dependability is a component of reliability that is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over‐tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability that is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re‐configuring the System. Such actions, if inadvertently taken, are undesirable
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC‐
012‐2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS‐entity or the reviewing RC(s) may
have alternative ideas or methods available to resolve the issue(s). In either case, the concern
needs to be resolved in deference to reliability, and the RC has the final decision.
A specific time period for the RAS‐entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS‐entity to effect a timely
implementation.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every 60
full calendar months. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it interacts with and impacts the
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BES. Requirement R4 also clarifies that the RAS single component failure and inadvertent
operation tests do not apply to RAS which are determined to be limited impact. Requiring a
limited impact RAS to meet the single component failure and inadvertent operation tests would
just add complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within sixty full
calendar months of the effective date of PRC‐012‐2. For new or functionally modified RAS, the
initial performance of the requirement must be completed within sixty full calendar months of
the RAS approval date by the reviewing RC(s). Sixty full calendar months was selected as the
maximum time frame between evaluations based on the time frames for similar requirements
in Reliability Standards PRC‐006, PRC‐010, and PRC‐014. The RAS evaluation can be performed
sooner if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. The periodic
RAS evaluation will typically lead to one of the following outcomes: 1) affirmation that the
existing RAS is effective; 2) identification of changes needed to the existing RAS; or, 3)
justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.4) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The PC is the functional entity best suited to perform the
analyses because they have a wide‐area planning perspective. To promote reliability, the PC is
required to provide the results of the evaluation to each RAS‐entity and reviewing RC, as well as
each impacted Planning Coordinator and Transmission Planner.
The intent of Requirement R4, Part 4.1.3 is to require that the possible inadvertent operation of
the RAS (other than limited impact RAS), caused by the malfunction of a single component of
the RAS, meet the same System performance requirements as those required for the
Contingency(ies) or System conditions for which it is designed. If the RAS is designed to meet
one of the planning events (P0‐P7) in TPL‐001‐4, the possible inadvertent operation of the RAS
must meet the same performance requirements listed in the standard for that planning event.
The requirement clarifies that the inadvertent operation to be considered is only that caused by
the malfunction of a single RAS component. This allows features to be designed into the RAS to
improve security, such that inadvertent operation due to malfunction of a single component is
prevented; otherwise, the RAS inadvertent operation must satisfy Requirement R4, Part 4.1.3.
The intent of Requirement R4, Part 4.1.3 is also to require that the possible inadvertent
operation of the RAS (other than limited impact RAS) installed for an extreme event in TPL‐001‐
4 or for some other Contingency or System conditions not defined in TPL‐001‐4 (therefore
without performance requirements), meet the minimum System performance requirements of
Category P7 in Table 1 of NERC Reliability Standard TPL‐001‐4. However, instead of referring to
the TPL standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.3.1 – 4.1.3.5) are the ones that are common to all planning events (P0‐P7) listed in
TPL‐001‐4.
With reference to Requirement 4, Part 4.1.3, note that the only differences in performance
requirements among the TPL (P0‐P7) events (not common to all of them) concern Non‐
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Consequential Load Loss and interruption of Firm Transmission Service. It is not necessary for
Requirement R4, Part 4.1.3 to specify performance requirements related to these areas
because a RAS is only allowed to drop non‐consequential load or interrupt Firm Transmission
Service if that action is allowed for the Contingency for which it is designed. Therefore, the
inadvertent operation should automatically meet Non‐Consequential Load Loss or interrupting
Firm Transmission Service performance requirements for the Contingency(ies) for which it was
designed.
Part 4.1.4 requires that a single component failure in the RAS (other than limited impact RAS),
when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. This analysis is needed to
ensure that changing System conditions do not result in the single component failure
requirement not being met.
Requirements for inadvertent RAS operation (Requirement R4, Part 4.1.3) and single
component failure (Requirement R4, Part 4.1.4) are reviewed by the reviewing RC(s) before a
new or functionally modified RAS is placed in‐service, and are typically satisfied by specific
design considerations. Although the scope of the periodic evaluation does not include a new
design review, it is possible that a design which previously satisfied requirements for
inadvertent RAS operation and single component failure may fail to satisfy these requirements
at a later time, and must be evaluated with respect to the current System. For example, if the
actions of a particular RAS include tripping load, load growth could occur over time that impacts
the amount of load to be tripped. These changes could result in tripping too much load upon
inadvertent operation and result in violations of Facility Ratings. Alternatively, the RAS might be
designed to trip more load than necessary (i.e., “over trip”) in order to satisfy single component
failure requirements. System changes could result in too little load being tripped and
unacceptable BES performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4 regarding
the investigation of a Protection System Misoperation; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
the RAS‐entity(s) is required to provide the results of RAS operational performance analyses to
its reviewing RC(s).
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The RAS‐entity(ies) may need to collaborate with its associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS‐entity for a RAS, the RAS‐entities would collaborate on the operational
performance analysis.
Requirement R6
RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may be identified
in the periodic RAS evaluation conducted by the PC in Requirement R4, in the operational
analysis conducted by the RAS‐entity in Requirement R5, or in the functional test performed by
the RAS‐entity(ies) in Requirement R8. To mitigate potential reliability risks, Requirement R6
mandates that each RAS‐entity participate in developing a CAP that establishes the mitigation
actions and timetable necessary to address the deficiency.
The RAS‐entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS‐entity(ies) may request assistance with development of the
CAP from other parties such as its Transmission Planner or Planning Coordinator; however, the
RAS‐entity has the responsibility for compliance with this requirement.
A CAP may require functional changes be made to a RAS. In this case, Attachment 1 information
must be submitted to the reviewing RC(s), an RC review must be performed to obtain RC
approval before the RAS‐entity can place RAS modifications in‐service, per Requirements R1,
R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering or consulting work. A timeframe of six full calendar months is allotted to allow
enough time for RAS‐entity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. A RAS deficiency may require the RC or
Transmission Operator to impose operating restrictions so the System can operate in a reliable
way until the RAS deficiency is resolved. The possibility of such operating restrictions will incent
the RAS‐entity to resolve the issue as quickly as possible.
The following are example situations of when a CAP is required:
A determination after a RAS operation/non‐operation investigation that the RAS did not
meet performance expectations or did not operate as designed.
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
Equipment failures.
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
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Requirement R7 mandates that each RAS‐entity implement its CAP developed in Requirement
R6 which mitigates the deficiencies identified in Requirements R4, R5, or R8. By definition, a
CAP is: “A list of actions and an associated timetable for implementation to remedy a specific
problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. If the CAP is changed, the RAS‐entity must notify the reviewing Reliability
Coordinator(s). The RAS‐entity must also notify the Reliability Coordinator(s) when the CAP has
been completed.
The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS‐entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non‐Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in‐service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC‐005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed with minimum impact to the
BES and should align with expected results. The RAS‐entity is in the best position to determine
the testing procedure and schedule due to their overall knowledge of the RAS design,
installation, and functionality. Periodic testing provides the RAS‐entity assurance that latent
failures may be identified and also promotes identification of changes in the System that may
have introduced latent failures.
The six and twelve full calendar year functional testing intervals are greater than the annual or
bi‐annual periodic testing performed in some NERC Regions. However, these intervals are a
balance between the resources required to perform the testing and the potential reliability
impacts to the BES created by undiscovered latent failures that could cause an incorrect
operation of the RAS. Longer test intervals for limited impact RAS are acceptable because
incorrect operations or failures to operate present a low reliability risk to the Bulk Power
System.
Functional testing is not synonymous with end‐to‐end testing. End‐to‐end testing is an
acceptable method but may not be feasible for many RAS. When end‐to‐end testing is not
possible, a RAS‐entity may use a segmented functional testing approach. The segments can be
tested individually negating the need for complex maintenance schedules. In addition, actual
RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does not
operate in its entirety during a System event or System conditions do not allow an end‐to‐end
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scheme test, then the segmented approach should be used to fulfill this Requirement.
Functional testing includes the testing of all RAS inputs used for detection, arming, operating,
and data collection. Functional testing also includes the processing logic and infrastructure of a
RAS as well as the action initiation by RAS outputs to address the System condition(s) for which
the RAS is designed. All segments and components of a RAS must be tested or have proven
operations within the applicable maximum test interval to demonstrate compliance with the
Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC‐005, Table 1‐1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up‐to the protective
relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3‐8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well‐defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component‐level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of Contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real‐time) to
the Transmission Operator via PRC‐001, Requirement R6, then to the RC via TOP‐001‐3,
Requirement R8. See Phase 2 of Project 2007‐06 for the mapping document from PRC‐001 to
other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
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The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end‐to‐end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS‐entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
maximum test interval that started on the date of the previous successful test of those (non‐
operating) segments in order to be compliant with Requirement R8.
Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available to entities with a potential reliability need. Attachment 3
contains the minimum information that is required to be included about each RAS listed in the
database. Additional information can be requested by the RC.
The information provided is sufficient for an entity with a reliability need to evaluate whether
the RAS can impact its System. For example, a RAS performing generation rejection to mitigate
an overload on a transmission line may cause a power flow change within an adjacent entity
area. This entity should be able to evaluate the risk that a RAS poses to its System from the
high‐level information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS‐entity from the RC.
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Process Flow Diagram
The diagram below depicts the process flow of the PRC‐012‐2 requirements.
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS‐entity(ies) to provide a detailed list of information
describing the RAS to the reviewing RC. If there are multiple RAS‐entities for a single RAS,
information will be needed from all RAS‐entities. Ideally, in such cases, a single RAS‐entity will
take the lead to compile all the data identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide‐ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified7 RAS that the RAS‐entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS‐entity
provides a summary of the existing RAS functionality.
I.
General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single‐line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012‐2, Requirements R5 and R7]
7
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement of existing components
•
Changes to RAS logic beyond error correcting
•
Changes to redundancy levels; i.e., addition or removal
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Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name
b. Each RAS‐entity and contact information
c. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date;
most recent 60 full calendar month (Requirement R4) evaluation date; and, date of
retirement, if applicable
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery)
e. Description of the Contingencies or System conditions for which the RAS was
designed (initiating conditions)
f. Corrective action taken by the RAS
g. Identification of limited impact8 RAS
h. Any additional explanation relevant to high level understanding of the RAS
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical System
Contingencies or other operating conditions when RAS action is intended to occur.
If no arming conditions are required, this should also be stated.
8
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact.
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c. Event‐based RAS are triggered by specific Contingencies that initiate mitigating
action. Condition‐based RAS may also be initiated by specific Contingencies, but
specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and when those technical studies were
performed. [Reference NEC Reliability Standard PRC‐014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS‐related operations.
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. RAS‐entity proposed designation as “limited impact” or not.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in
WECC will be recognized as limited impact for the purposes of Requirement 4, Parts
4.1.3 and 4.1.4.
6. Documentation showing that the possible inadvertent operation of the RAS resulting
from any single RAS component malfunction satisfies all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
b. Cascading shall not occur.
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c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or re‐
configuring the System. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available fault duty,
which can affect distance relay overcurrent (“fault detector”) supervision and ground
overcurrent protection coordination.
8. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, logic processing, control actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be designed
to be secure. Several types of devices have been commonly used as disturbance, condition,
or status detectors:
Line open status (event detectors),
Protective relay inputs and outputs (event and parameter detectors),
Transducer and IED (analog) inputs (parameter and response detectors),
Rate of change (parameter and response detectors).
DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by PRC‐
005. However, redundant RAS systems, when used, should be supplied from separately
protected (fused or breakered) circuits.
Communications: Telecommunications Channels and Transfer Trip Equipment
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non‐deterministic
communication systems used (such as Ethernet).
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Supplemental Material
The scheme logic should be designed so that loss of the channel, noise, or other channel or
equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS‐entity, or
perhaps leased from another entity familiar with the necessary reliability requirements. All
channel equipment should be monitored and alarmed to the dispatch center so that timely
diagnostic and repair action shall take place upon failure. Publicly switched telephone
networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel working
on the channel can readily identify the proper circuit. Channels between entities should be
identified with a common name at all terminals.
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions may
be required at different arming levels or for different Contingencies. Scheme logic may be
achievable by something as simple as wiring a few auxiliary relay contacts or by much more
complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units (RTUs),
and logic processors. Single‐function relays have been used historically to implement RAS,
but this approach is now less common except for very simple new RAS or minor additions to
existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS actions
at the sites where action is required.
Monitoring by SCADA/EMS should include at least
Whether the scheme is in‐service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in‐service or out of service.
For RAS that are armed automatically, these two states are independent because a
RAS that has been placed in‐service may be armed or unarmed based on whether
the automatic arming criteria have been met.
The current operational state of the scheme (available or not).
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In cases where the RAS requires single component failure performance; e.g.,
redundancy, the minimal status indications should be provided separately for each
system.
The minimum status is generally sufficient for operational purposes; however,
where possible it is often useful to provide additional information regarding partial
failures or the status of critical components to allow the RAS‐entity to more
efficiently troubleshoot a reported failure. Whether this capability exists will depend
in part on the design and vintage of equipment used in the RAS. While all schemes
should provide the minimum level of monitoring, new schemes should be designed
with the objective of providing monitoring at least similar to what is provided for
microprocessor‐based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line‐charging current;
c. Breaker trip coil current monitoring—typically used when high‐speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of the
aforementioned, out of step, etc. are dependent on specific scheme requirements,
but some forms may substitute for or enhance other monitoring described in items
‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in‐service or is being
maintained.
In this context, a multifunction device (e.g., microprocessor‐based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
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Supplemental Material
the RAS function is applied in the same microprocessor‐based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi‐function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective. [Reference NERC Reliability Standard PRC‐012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement. Acceptable methods to achieve this objective
include, but are not limited to the following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
Protective or auxiliary relays used by the RAS.
ii.
Communications systems necessary for correct operation of the RAS.
iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
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vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation due to that single component failure will still result in
satisfactory System performance, as long as tripping the total armed amount of load
or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re‐dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS‐entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies, if applicable, upon which the decision to retire the RAS
is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Supplemental Material
Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent‐wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability‐related considerations relevant to various aspects of RAS design and
implementation.
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
The name used to identify the RAS.
2. Each RAS‐entity and contact information.
A reliable phone number or email address should be included to contact each RAS‐entity
if more information is needed.
3. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date; most
recent 60 full calendar month (Requirement R4) evaluation date; and, date of retirement, if
applicable.
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under‐/over‐voltage, slow voltage
recovery).
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the Contingencies or System conditions for which the RAS was designed
(initiating conditions).
A high level summary of the conditions/Contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
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Supplemental Material
7. Identification of limited impact9 RAS.
Specify whether or not the RAS is designated as limited impact.
8. Any additional explanation relevant to high‐level understanding of the RAS.
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
9
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
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PRC‐012‐2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 12 of PRC‐012‐2 corrects the applicability of the fill‐in‐the‐blank standards (PRC‐012‐1,
PRC‐013‐1, and PRC‐014‐1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk‐Power System, and incorporates the reliability objectives of
all the RAS/SPS‐related standards. Draft 1This draft contains nine requirements and measures,
the associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. Draft 1ofThis draft of PRC‐012‐2 is posted for a 45‐day initial formal comment
period with a parallel initial ballot in the last ten days of the comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC‐012‐2 posted for informal comment
April 30 – May 20, 2015
45‐day formal comment period with initial ballot
August 20 – October 5,
2015
45‐day formal comment period with additional ballot
November 25, 2015 –
January 8, 2016
Anticipated Actions
Date
10‐day final ballot
December 2015March
2016
NERC Board (Board) adoption
FebruaryMay 2016
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PRC‐012‐2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
3.
Number:
Purpose:
PRC‐012‐2
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Transmission Planner
4.1.2. Planning Coordinator
4.1.3. RAS‐ownerentity – the Transmission Owner, Generator Owner, or
Distribution Provider that owns all or part of a RAS
4.1.4. RAS‐entity – the RAS‐owner designated to represent all RAS‐owner(s) for
coordinating the review and approval of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC‐012‐2.
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PRC‐012‐2 – Remedial Action Schemes
B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement (; i.e., removal from service) must be completed
prior to implementation or retirement. A functional modification is
Functional modifications consist of any modificationof the following:
Changes to a RASSystem conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond thein‐kind replacement of existing components
that preserves the original functionality.
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS‐entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS‐entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. Ideally, when there is more than one RAS‐entity for
a RAS, the RAS‐entities would collaborate and submit a single, coordinated Attachment 1
to the reviewing RC. In cases where a RAS crosses one or more RC Area boundaries, each
affected RC is responsible for conducting either individual reviews or participating in a
coordinated review.
R1.
Prior to placing a new or functionally modified RAS in ‐service or retiring an existing
RAS, each RAS‐entity shall submitprovide the information identified in Attachment 1
for review to the Reliability Coordinator(s) that coordinates the area(s) where the RAS
is located. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest‐area operational and reliability perspective of all
functional entities and an awareness of reliability issues in any neighboring RC Area. This
Wide Area purview provides continuity in the review process and facilitates the
evaluation of interactions among separate RAS as well as interactions among RAS and
other protection and control systems. IncludingReview by the RC also minimizes the
possibility of a conflict of interest that could exist because of business relationships
among the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP), or other
entities that are likely to be involved in the planning or implementation of a RAS. The RC
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PRC‐012‐2 – Remedial Action Schemes
is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The RC may request assistance into perform RAS
reviews from other parties such as the PC or regional technical groups; however, the RC
will retain the responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each RAS submitted
RAS. The time frame of four‐ full‐ calendar months is consistent with current utility and
regional practice; however, flexibility is provided by allowing the partiesRC(s) and RAS‐
entity(ies) to negotiate a mutually agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1, shall, within four‐ full‐ calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to theeach RAS‐entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS‐entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in ‐service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS‐entity to respond to the RC reviewreviewing RC
following identification of any reliability issue(s) is not necessary because it is in the RAS‐
entity’s interestentity wants to obtain an expeditious response fromexpedite the entity
and thus ensure a timely approval and subsequent implementation. of the RAS.
R3.
Following the review performed pursuant to Requirement R2, the RAS‐entity shall
address each identified issue and obtain approval from each reviewing Reliability
Coordinator priorPrior to placing a new or functionally modified RAS in ‐service or
retiring an existing RAS., each RAS‐entity that receives feedback from the reviewing
Reliability Coordinator(s) identifying reliability issue(s) shall resolve each issue to
obtain approval of the RAS from each reviewing Reliability Coordinator. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
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PRC‐012‐2 – Remedial Action Schemes
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every sixty‐ full‐ calendar months. The purpose of athe
periodic RAS evaluation is to verify the continued effectiveness and coordination of the
RAS, as well as to verify that requirements for BES performance following an inadvertent ,
if a RAS operation or a single component failure in the RAS continuesor single component
malfunction were to occur, the requirements for BES performance would continue to be
satisfied. AThe periodic evaluation is needed because changes in systemSystem topology
or operating conditions that have occurred since the previous RAS evaluation—or initial
review—was completed may change the effectiveness of a RAS or the way it impacts the
BES.
Sixty‐full‐calendar months, Requirement R4 also clarifies that the RAS single component
failure and single component malfunction tests do not apply to RAS which begins onare
determined to be limited impact. A RAS designated as limited impact cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading,
uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations. A RAS implemented after the effective date of thethis
standard pursuant towill be designated as limited impact or not by the implementation
plan,reviewing RC(s) during its review. A RAS implemented prior to the effective date of
this standard that has been through the regional review process and designated as Type 3
in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact for the
purposes of Requirement 4, Parts 4.1.3 and 4.1.4. Requiring a limited impact RAS to meet
the single component failure and single component malfunction tests would add
complexity to the design with minimal benefit to the reliability of the BES. See
Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator.
For existing RAS, the initial performance of Requirement R4 must be completed within
sixty full calendar months of the effective date of PRC‐012‐2. For new or functionally
modified RAS, the initial performance of the requirement must be completed within sixty
full calendar months of the RAS approval date by the reviewing RC(s). Sixty full calendar
months was selected as the maximum time frame between evaluations based on the time
frames for similar requirements in Reliability Standards PRC‐006, PRC‐010, and PRC‐014.
The RAS evaluation can be performed sooner if it is determined that material changes to
systemSystem topology or systemSystem operating conditions have occurred that could
potentially impact the effectiveness or coordination of the RAS. The periodic RAS
evaluation will typically lead to one of the following outcomes: 1) affirmation that the
existing RAS is effective; 2) identification of changes needed to the existing RAS; or, 3)
justification for RAS retirement.
The items required to be addressed in the evaluation are planning analyses thatmay
involve modeling of the interconnected transmission system to assess BES performance;
consequently, the TP. The Planning Coordinator (PC) is the functional entity best suited to
perform the analyses.this evaluation because they have a wide area planning perspective.
To promote reliability, the TPPC is required to provide the RAS‐owner(s) and each
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PRC‐012‐2 – Remedial Action Schemes
reviewing RC with the results of the evaluation. to each impacted Transmission Planner
and Planning Coordinator, in addition to each reviewing RC and RAS‐entity.
The previous version of this standard (PRC‐012‐01 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL‐001‐
0, TPL‐002‐0, and TPL‐003‐0) as that required of the contingencyContingency for which it
was designed, and not exceed TPL‐003‐0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise
and, consistent with PRC‐012‐01 Requirement 1, R1.4, the RAS should be designed so that
its whole or partial inadvertent operation due to a single component malfunction satisfies
the systemSystem performance requirements for the same Contingency for which the
RAS was designed.
If the RAS was installed for an extreme event in TPL‐001‐4 or for some other Contingency
or System condition not defined in TPL‐001‐4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL‐001‐4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.1.3.1 – 4.1.3.5) are the ones that
are common to all planning events P0‐P7 listed in TPL‐001‐4.
R4.
Each Transmission Planner shall perform an evaluation of each RAS within its planning
area Planning Coordinator, at least once every 60‐ full‐ calendar‐ months and provide
the RAS‐owner(s) and the reviewing Reliability Coordinator(s) the results including any
identified deficiencies. Each evaluation shall determine whether:, shall: [Violation Risk
Factor: Medium] [Time Horizon: Long‐term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.4.1.1.
The RAS mitigates the System condition(s) or Contingency(ies) for
which it was designed.
4.2.4.1.2.
The RAS avoids adverse interactions with other RAS, and
protection and control systems.
4.3.4.1.3.
The Except for “limited impact”1 RAS, the possible inadvertent
operation of the RAS, resulting from any single RAS component
malfunction satisfies all of the following:
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
1
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4.3.1.4.1.3.1. The BES shall remain stable.
4.3.2.4.1.3.2. Cascading shall not occur.
4.3.3.4.1.3.3. Applicable Facility Ratings shall not be exceeded.
4.3.4.4.1.3.4. BES voltages shall be within post‐Contingency voltage
limits and post‐Contingency voltage deviation limits as
established by the Transmission Planner and the Planning
Coordinator.
4.3.5.4.1.3.5. Transient voltage responses shall be within acceptable
limits as established by the Transmission Planner and the
Planning Coordinator.
4.4.4.1.4.
AExcept for limited impact RAS, a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS‐entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS‐owner(s)entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation iswas
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120‐ full calendar‐ day time frame for the completion of RAS operational
performance analysis aligns with the time frame established in Requirement R1 from PRC‐
004‐4 regarding the investigation of a Protection System Misoperation. To promote
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4.
Draft 12 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
reliability, each RAS‐ownerentity is required to provide the results of RAS operational
performance analyses to eachthat identified any deficiencies to its reviewing RC.(s).
RAS‐ownersentities may need to collaborate with their associated TPTransmission
Planner to comprehensively analyze RAS operational performance. This is because a RAS
operational performance analysis involves verifying that the RAS operation triggers and
responds (Partswas triggered correctly (Part 5.1,.1), responded as designed (Part 5.1.2)),
and that the resulting BES response (Parts 5.1.3, and 5.1.4) iswas consistent with the
intended functionality and design of the RAS. Ideally, when there is more than one RAS‐
entity for a RAS, the RAS‐entities would collaborate on the operational performance
analysis.
R5.
Each RAS‐owner shallentity, within 120‐ full calendar days of a RAS operation or a
failure of aits RAS to operate when expected, analyze the RAS performance and
provide the results of the analysis, including any identified deficiencies, toor on a
mutually agreed upon schedule with its reviewing Reliability Coordinator(s). The RAS
operational performance analysis shall determine whether: ), shall: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.5.1.1.
The System events and/or conditions appropriately triggered the
RAS.
5.2.5.1.2.
The RAS responded as designed.
5.3.5.1.3.
The RAS was effective in mitigating BES performance issues it was
designed to address.
5.4.5.1.4.
The RAS operation resulted in any unintended or adverse BES
response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with the reviewing Reliability Coordinator(s) in accordance with Requirement R5.
Rationale for Requirement R6: Deficiencies, identified either in the periodic RAS
evaluation conducted by the TP inPC pursuant to Requirement R4 or, in the operational
performance analysis conducted by the RAS‐ownerentity pursuant to Requirement R5,
are likely toor in the functional test performed by the RAS‐entity pursuant to
Requirement R8, potentially pose a reliability risk to the BES. To mitigate these potential
reliability risks, Requirement R6 mandates that theeach RAS‐ownerentity develop a
Corrective Action Plan (CAP) that establishesto address the identified deficiency. The CAP
contains the mitigation actions and associated timetable to address the deficiency.
necessary to remedy the specific deficiency. The RAS‐entity may request assistance with
Draft 12 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
CAP development from other parties such as its Transmission Planner or Planning
Coordinator; however, the RAS‐entity has the responsibility for compliance with this
requirement.
If the CAP requires that a functional change be made to a RAS, the RAS‐ownerentity will
need to submit information identified in Attachment 1 to the reviewing RC(s) prior to
placing RAS modifications in ‐service per Requirement R1.
Depending on the complexity of the issues,identified deficiency(ies), development of a
CAP mightmay require study,studies, and other engineering, or consulting work. A
maximum time frame of six‐ full‐ calendar months is specified to allow enough time for
RAS‐ownerentity collaboration on the CAP development, while ensuring that deficiencies
are addressed in a reasonable time. .
R6.
Within six‐full‐calendar months of being notified of a deficiency in its RAS pursuant to
Requirement R4 or Requirement R5, each RAS‐ownerEach RAS‐entity shall participate
in developing a Corrective Action Plan (CAP) and submit the CAP to its reviewing
Reliability Coordinator(s).) within six full calendar months of: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning, Long‐term Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator pursuant to Requirements R5, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications withamong each reviewing Reliability Coordinator and each RAS‐
entity in accordance with Requirement R6.
Rationale for Requirement R7: Requirement R7 mandates theeach RAS‐owner(s)entity
implement a CAP (developed in Requirement R6) that mitigates the deficiencies identified
in Requirements R4 and, R5, or R8. By definition, a CAP is: “A list of actions and an
associated timetable for implementation to remedy a specific problem.” The
implementation of a properly developed CAP ensures that RAS deficiencies are mitigated
in a timely manner. Each reviewing Reliability Coordinator must be notified if CAP actions
or timetables change., and when the CAP is completed.
R7.
ForEach RAS‐entity shall, for each CAP submittedof its CAPs developed pursuant to
Requirement R6, each RAS‐owner shall: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning, Long‐term Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
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PRC‐012‐2 – Remedial Action Schemes
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the appropriatereviewing Reliability
Coordinator(s) that documents the implementation or, updating, or completion of a
CAP in accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non‐Protection System (control) components of a RAS that are not addressed in PRC‐005.
Protection System components that are part of a RAS are maintained in accordance with
PRC‐005. The drafting team selected a six‐calendar‐year testing interval to be consistent
with some of the maintenance intervals of various Protection System and Automatic
Reclosing components established in PRC‐005. This interval provides an entity the
opportunity to design its RAS functional testing program such that it coincides with the
testing of any associated PRC‐005 components.
The six‐ or twelve full calendar‐ year test interval, which begins on the effective date of
the standard pursuant to the PRC‐012‐2 implementation plan, is a balance between the
resources required to perform the testing and the potential reliability impacts to the BES
created by undiscovered latent failures that could cause an incorrect operation of the
RAS. Extending to longer intervals increases the reliability risk to the BES posed by a
potentiallyan undiscovered latent failure that could cause an incorrect operation or
failure of the RAS. The RAS‐ownerentity is in the best position to determine the testing
procedure and schedule due to its overall knowledge of the RAS design, installation, and
functionality. Functional testing may be accomplished with end‐to‐end testing or a
segmented approach. EachFor segmented testing, each segment of a RAS shouldmust be
tested but overlapping. Overlapping segments can be tested individually negating the
need for complex maintenance schedules and outages.
The maximum allowable interval between functional tests is six full calendar years for RAS
that are not designated as limited impact RAS and twelve full calendar years for RAS that
are designated as limited impact RAS. The interval between tests begins on the date of
the most recent successful test for each individual segment or end‐to‐end test. A
successful test of one segment only resets the test interval clock for that segment. A
correct operation of a RAS qualifies as a functional test as long as allfor those RAS
segments which operate. (documentation for compliance with Requirement R5 Part 5.1).
If an event causes a partial operation of a RAS, the segments without an operation will
require a separate functional test within the six year interval to be compliant with
Requirement R8maximum interval with the starting date determined by the previous
successful test of the segments that did not operate.
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PRC‐012‐2 – Remedial Action Schemes
R8.
At least once every six‐calendar years, eachEach RAS‐ownerentity shall
performparticipate in performing a functional test of each of its RAS to verify the
overall RAS performance and the proper operation of non‐Protection System
components.: [Violation Risk Factor: High] [Time Horizon: Long‐term Planning]
At least once every six full calendar years for all RAS not designated as limited
impact, or
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation
ofdetailing the RAS operational performance analysis for a correct RAS segment or an
end‐to‐end operation (Measure M5 documentation), or dated documentation
demonstrating that a functional testingtest of each RAS segment or an end‐to‐end
test was performed in accordance with Requirement R8.
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high‐level information on existing RAS that cancould potentially impact the
entities’ operational and/or planning activities of that entity. Attachment 3 lists the
minimum information required for the RAS database, which includes a summary of the
RAS initiating conditions, corrective actions, and System issues being mitigated. This
information allows an entity to evaluate the reliability need for requesting more detailed
information from the RAS‐entityentities identified in the database contact information.
The RC is the appropriate entity to maintain the database because the RC receives the
required database information when a new or modified RAS is submitted for review. The
twelve full calendar month time frame is aligned with industry practice and allows
sufficient time for the RC to collect the appropriate information from RAS‐entities and
update the RAS database.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once eachevery twelve full calendar
yearmonths. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was
maintainedupdated in accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
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PRC‐012‐2 – Remedial Action Schemes
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS‐entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1 through, R3, R5, R6, R7, and R8, and Measures M1, M3, M5,
M6, M7, and M8 since the last audit, unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M1 throughM2 and M9 since the
last audit, unless directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS‐entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non‐compliant, it shall
keep information related to the non‐compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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PRC‐012‐2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS‐entity failed to
submitprovide the
information identified in
Attachment 1 to one or
more of theeach Reliability
Coordinator(s) prior to
placing a new or functionally
modified RAS in‐service or
retiring an existing RAS in
accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30‐ full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30‐ full
calendar days but less than
or equal to 60‐ full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60‐ full
calendar days but less than
or equal to 90‐ full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90‐ full
calendar days.
Draft 12 of PRC‐012‐2
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OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
Page 13
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
accordance with
Requirement R2.
R3.
N/A
N/A
N/A
The RAS‐entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS in
‐service or retiring an
existing RAS in accordance
with Requirement R3.
R4.
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 60‐ full‐
calendar months but less
than or equal to 61‐ full‐
calendar months.
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 61‐ full‐
calendar months but less
than or equal to 62‐ full‐
calendar months.
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 62‐ full‐
calendar months but less
than or equal to 63‐ full‐
calendar months.
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 63‐ full‐
calendar months.
OR
The Transmission Planner
failed to perform the
evaluation in accordance
The Transmission
PlannerPlanning Coordinator with Requirement R4.
performed the evaluation in
OR
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1.1 through 4.1.4.
OR
The Transmission
PlannerThe Planning
Coordinator performed the
evaluation in accordance
with Requirement R4, but
failed to evaluate two or
more of the Parts 4.1.1
through 4.1.4.
OR
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the RAS‐owner(s)
and the reviewing Reliability
Coordinator(s).receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
Draft 12 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
R5.
The RAS‐ownerentity
performed the analysis in
greater than 120‐calendar
days, but less than or equal
to 130‐calendar days in
accordance with
Requirement R5, but was
late by less than or equal to
10 full calendar days.
Moderate VSL
High VSL
Severe VSL
The RAS‐ownerentity
performed the analysis in
greateraccordance with
Requirement R5, but was
late by more than 130‐10 full
calendar days, but less than
or equal to 140‐20 full
calendar days in accordance
with Requirement R5.
The RAS‐ownerentity
performed the analysis in
greateraccordance with
Requirement R5, but was
late by more than 140‐20 full
calendar days, but less than
or equal to 150‐30 full
calendar days in accordance
with Requirement R5.
The RAS‐ownerentity
performed the analysis in
greateraccordance with
Requirement R5, but was
late by more than 150‐30 full
calendar days.
OR
The RAS‐owner failed to
perform the analysis in
accordance with
Requirement R5.
OR
The RAS‐ownerentity
performed the analysis in
accordance with
Requirement R5, but failed
to address one of the Parts
5.1.1 through 5.1.4.
OR
The RAS‐ownerThe RAS‐
entity performed the
analysis in accordance with
Requirement R5, but failed
to address two or more of
the Parts 5.1.1 through 5.1.4.
OR
The RAS‐ownerentity
performed the analysis in
accordance with
Requirement R5, but failed
to provide the results (Part
5.2) to one or more of the
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
reviewing Reliability
Coordinator(s).
OR
The RAS‐entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS‐ownerentity
developed a Corrective
Action Plan and submitted it
to its reviewing Reliability
Coordinator(s) in accordance
with Requirement R6, but
was late by less than or
equal to 10‐ full calendar
days.
The RAS‐ownerentity
developed a Corrective
Action Plan and submitted it
to its reviewing Reliability
Coordinator(s) in accordance
with Requirement R6, but
was late by more than 10‐
full calendar days but less
than or equal to 20‐ full
calendar days.
The RAS‐ownerentity
developed a Corrective
Action Plan and submitted it
to its reviewing Reliability
Coordinator(s) in accordance
with Requirement R6, but
was late by more than 20‐
full calendar days but less
than or equal to 30‐ full
calendar days.
The RAS‐ownerentity
developed a Corrective
Action Plan and submitted it
to its reviewing Reliability
Coordinator(s) in accordance
with Requirement R6, but
was late by more than 30‐
full calendar days.
OR
The RAS‐ownerentity
developed a Corrective
Action Plan andbut failed to
submit it to one or more of
its reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The RAS‐ownerentity failed
to develop a Corrective
Action Plan in accordance
with Requirement R6.
R7.
The RAS‐ownerentity
implemented a CAP (in
accordance with
Requirement R7, Part 7.1),,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed and, or
failed to notify one or
more(Part 7.3) each of the
reviewing Reliability
Coordinator(s) (Part 7.3), in
accordance with
Requirement R7of the
updated CAP or completion
of the CAP.
N/A
N/A
The RAS‐ownerentity failed
to implement a CAP (Part
7.1) in accordance with
Requirement R7, Part 7.1.
R8.
The RAS‐ownerentity
performed the functional
test for a RAS as specified in
Requirement R8, but was
late by less than or equal to
30‐ full calendar days late.
The RAS‐ownerentity
performed the functional
test for a RAS as specified in
Requirement R8, but was
late by more than 30‐ full
calendar days but less than
or equal to 60‐ full calendar
days late.
The RAS‐ownerentity
performed the functional
test for a RAS as specified in
Requirement R8, but was
late by more than 60‐ full
calendar days but less than
or equal to 90‐ full calendar
days late.
The RAS‐ownerentity
performed the functional
test for a RAS as specified in
Requirement R8, but was
late by more than 90‐ full
calendar days late.
Draft 12 of PRC‐012‐2
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OR
Page 18
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The RAS‐ownerentity failed
to perform the functional
test for a RAS as specified in
Requirement R8.
R9.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30‐ full calendar days.
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The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30‐ full
calendar days but less than
or equal to 60‐ full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60‐ full
calendar days but less than
or equal to 90‐ full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90‐ full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
Page 19
PRC‐012‐2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
Date
Action
Change Tracking
1
Adopted by NERC Board of Trustees
New
Draft 12 of PRC‐012‐2
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Page 20
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified2 RAS that the RAS‐entity shallmust document and
provide to the reviewing Reliability Coordinator(s) (RC) for review.). If an item on this list
does not apply to a specific RAS, a response of N/A or “Not Applicable” for that item is
appropriate. When a RAS has been previously reviewedare submitted for functional
modification review and approval, only the proposed modifications to that RAS require
review; however, the RAS‐entity must provide a summary of the previously
approvedexisting functionality. The RC may request additional information on any aspect of
the RAS as well as any reliability issue related to the RAS. Additional entities (without
decision authority) may be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012, Requirements R5 and R7]
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐
voltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
2
f. Action(s) to be taken by the RAS.
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond thein‐kind replacement of existing components that preserve the original
functionality is a functional modification.
•
Changes to RAS logic beyond error correcting
•
Changes to redundancy levels; i.e., addition or removal
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g. Identification of limited impact3 RAS.
h. Any additional explanation relevant to high‐level understanding of the RAS.
b.1.
Functional RAS‐entity and contact information.
c.1. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d.1.
System performance issue or reason for installing the RAS (e.g., thermal
overload, angular instability, poor oscillation damping, voltage instability, under‐ or
over‐voltage, or slow voltage recovery).
II.
Description of the contingencies or and Transmission Planning Information
e.1.
Contingencies and System conditions for whichthat the RAS was designed (i.e.,
initiating conditions).is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS‐entity proposed designation as limited impact or not.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
3
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact.
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7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
f. Action(s) to be taken by the RAS.
g.a. Any additional explanation relevant to high‐level understanding of the RAS.
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II.I. Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
2.1.
The action(s) to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed. [Reference NERC Reliability Standard PRC‐014, R3.2]
4.1.
Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
1. Documentation showing that the possible inadvertent operation of the RAS resulting
from any single RAS component malfunction satisfies all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
b.a.
Cascading shall not occur.
c.a. Applicable Facility Ratings shall not be exceeded.
d.a. BES voltages shall be within post‐Contingency voltage limits and post‐
Contingency voltage deviation limits as established by the Transmission Planner and
the Planning Coordinator.
e.a.Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
5.1.
An evaluation indicating that the RAS settings and operation avoid adverse
interactions with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
6.8.
Identification of other affected RCs.
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III. Implementation
III.I.
Implementation
1. Documentation describing the applicable equipment used for detection,
telecommunicationsdc supply, communications, transfer trip, control actions, logic
processing, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.Information on detection logic and settings/parameters that control the
operation of the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013,
R1.3]
2.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in ‐service or is being
maintained.
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4. Documentation showing thatdescribing the System performance resulting from a single
component failure in the RAS, except for limited impact RAS, when the RAS is intended
to operate. A single component failure in a RAS not determined to be limited impact
must not prevent the BES from meeting the same performance requirements (defined
in Reliability Standard TPL‐001‐4 or its successor) as those required for the events and
conditions for which the RAS is designed. The documentation should describe or
illustrate how the design achieves this objective.
4.1.
, does not prevent the BES from meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its successor) as those required for the
events and conditions for which the RAS is designed. The documentation should
describe or illustrate how the design achieves this objective.
[Reference NERC Reliability Standard PRC‐012, R1.3]
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS‐entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
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Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability‐related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any reliability issue related to the RAS.aspect of the RAS as well as any reliability
issue related to the RAS. If a checklist item is not relevant to a particular RAS, it should be noted
as “Not Applicable.” If reliability considerations are identified during the review, the
considerations and the proposed resolutions should be documented with the remaining
applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
3. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
4. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate (if non‐operation for RAS single component failure is acceptable),, have been
identified.
5. TheDetermination whether or not the RAS is “limited impact.5” A RAS designated as
limited impact cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations.
5.6.
Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
4
Functionally Modified:
Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond thein‐kind replacement of existing components that preserve the original
functionality is a functional modification.
•
•
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
5
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
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c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
6.7.
The effects of future BES modifications on the design and operation of the RAS
have been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. The timing of RAS action(s) is appropriate to its BES performance objectives.
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3. AExcept for limited impact RAS as determined by the RC, a single component failure in a
RAS does not prevent the BES from meeting the same performance requirements as
those required for the events and conditions for which the RAS is designed.
4. The RAS design facilitates periodic testing and maintenance.
5. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
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Attachment 3
Database Information
1. RAS name.
2. Each RAS‐entity and contact information.
3. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact6 RAS.
2.a.RAS‐entity and contact information.
3.a.Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4.a.System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐
voltage, or slow voltage recovery).
5.a.Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
6.a.Action(s) to be taken by the RAS.
7.8.
Any additional explanation relevant to high‐level understanding of the RAS.
6
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
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Technical Justifications for Requirements
Applicability
4.1.4 RAS‐1 Reliability Coordinator
The Reliability Coordinator (RC) is the best‐suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest‐area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide‐
Area purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
The purpose of the RAS‐entity is to be the single information conduit with each reviewing
Reliability Coordinator (RC) for all RAS‐owners for each RAS. The RAS‐entity needs to
coordinate all review materials and any presentations. If all of the RAS equipment has a single
owner, then the RAS‐entity is the same as the RAS‐owner and that owner speaks for itself.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best‐suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS‐entity
The RAS‐entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RAS‐
entity has sole responsibility for all the activities assigned within the standard to the RAS‐entity.
If the RAS equipment has(RAS components) have more than one owner, then each separate
RAS equipment owner is a RAS‐owner. The RAS‐entity will always be one of these RAS‐owners.
A RAS‐entity will be selected by all RAS‐owners and, traditionally, has usually been the owner of
the RAS controller and a Transmission Owner. If a specific RAS‐entity is not component owner is
a RAS‐entity and is obligated to participate in various activities identified by the RAS‐owners,
the RC will assign that function to the RAS‐owner who provides theRequirements.
The standard does not stipulate particular compliance methods. RAS‐entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
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requirements; however, the individual RAS‐entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS‐entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review material to themprocess.
The RAS‐owner(s); i.e., Transmission Owner(s), Generator Owner(s), or Distribution Provider(s)
who are not the RAS‐entity still have responsibilities as assigned in other NERC Reliability
Standards, such as equipment maintenance. In addition, when RAS modifications are needed,
each RAS‐owner of RAS equipment that must be modified must accept the specific
responsibilities assigned to them as described in the necessary Corrective Action Plan (CAP), or
otherwise as described in the revised Attachment 1.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Any modificationFunctional modifications consists of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond the substitutionin‐kind replacement of existing
components
Changes to RAS logic beyond error correcting
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in‐kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that merely preserve
uses similar functions. For instance, if a RAS included a CO‐11 relay which was replaced by an
IAC‐53 relay, that would be an in‐kind replacement. If the CO‐11 relay were replaced by a
microprocessor SEL‐451 relay that used only the same functions as the original functionality is
CO‐11 relay, that would also be an in‐kind replacement; however, if the SEL‐451 relay was used
to add new logic to what the CO‐11 relay had provided, then the replacement relay would be a
functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. AnyFor example, System conditions require a RAS to be armed when
the combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to
Requirement R4, or other assessment, indicates that the arming level should be reduced to 450
MW without requiring any other RAS changes that would not be a functional modification.
Similarly, if a RAS is designed to shed load to reduce loading on a particular line below 1000
amps, then a change in RAS logic such as new the load shedding trigger from 1000 amps to
1100 amps would not be a functional modification.
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Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs or outputs, or any other modification that affects overall RAS
functionality, or redundancy level as documented in the original submissionto the RAS) and the
logic to recognize the specific line outages would change, while the generation reduction (RAS
output) requirement may or may not change, depending on which line is out of service. These
required RAS changes would be a functional modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for review aresuch functional
modifications. RAS modifications may be identified by a CAP pursuant to Requirement R6
beyond the substitution of components that merely preserve the original functionality are
functional in several ways including but not limited to the Planning evaluations pursuant to R4,
incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning assessments
related to future additions or modifications. RAS removal is essentially a form of RAS functional
modification. Any RAS proposed for removal needs to be evaluated under the RAS Retirement
section of the Attachment 1 checklist.
of other facilities.
To facilitate a review that promotes reliability, the RAS‐entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS‐entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS‐entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RAS‐
ownerentity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
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RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS‐owner(s). entity(ies). An independent review by a multi‐disciplinary panel of subject matter
experts with planning, operations, protection, telecommunications, and equipment expertise is
an effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the
widest‐area reliability perspective of all functional entities and an awareness of reliability issues
in neighboring RC Areas. This Wide Area purview provides continuity in the review process and
facilitates the evaluation of interactions among separate RAS as well as interactions among the
RAS and other protection and control systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS‐entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement.
It is recognized that the RC does not possesses more information or ability than anticipated by
their functional registration as designated by NERC. The NERC Functional Model is a guideline
for the development of standards and their applicability and does not contain compliance
requirements. If Reliability Standards address functions that are not described in the model, the
Reliability Standard requirements take precedence over the Functional Model. For further
reference, please see the Introduction section of NERC’s Reliability Functional Model, Version 5,
November 2009.
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
RAS for review. The time frame of four‐ full‐ calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
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Requirement R3
Requirement R3 mandates that theeach RAS‐entity addressresolve all reliability issues
(pertaining to its RAS) identified by the reviewing RC during the RAS review, and obtain
approval from the reviewing RC that the RAS implementation can proceed. The review by the
RC is intended to identify reliability issues that must be resolved before the RAS can be put in
service. by the reviewing Reliability Coordinators. Examples of reliability issues include a lack of
dependability, security, or coordination. RC approval of a RAS is considered to be obtained
when the reviewing RC’s feedback to each RAS‐entity indicates that either no reliability issues
were identified during the review or all identified reliability issues were resolved to the RC’s
satisfaction.
Dependability is a component of reliability andthat is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over‐tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability andthat is the measure of certainty of a device to not
operate inadvertently. False or inadvertent operation of a RAS results in taking a programmed
action without the appropriate arming conditions, occurrence of specified Contingency(ies), or
System conditions expected to trigger the RAS action. Typical RAS actions include shedding load
or generation or re‐configuring the System. Such actions, if inadvertently taken, are undesirable
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC‐
012‐2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS‐entity (and any other RAS‐owner) or
the reviewing RC(s) may have alternative ideas or methods available to resolve the issue(s). In
either case, the concern needs to be resolved in deference to reliability, and the RC has the final
decision.
A specific time period for the RAS‐entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS‐ownerentity to effect a timely
implementation.
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Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every 60‐
full‐ calendar months. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in systemSystem topology or
operating conditions that have occurred since the previous RAS evaluation (or initial review)
may change the effectiveness of a RAS or the way it interacts with and impacts the BES.
A period Requirement R4 also clarifies that the RAS single component failure and inadvertent
operation tests do not apply to RAS which are determined to be limited impact. Requiring a
limited impact RAS to meet the single component failure and inadvertent operation tests would
just add complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within sixty‐
full‐ calendar months of the effective date of PRC‐012‐2. For new or functionally modified RAS,
the initial performance of the requirement must be completed within sixty full calendar months
of the RAS approval date by the reviewing RC(s). Sixty full calendar months was selected as the
maximum time frame between evaluations based on the time frames for similar requirements
in NERC Reliability Standards PRC‐006, PRC‐010, and PRC‐014. The RAS evaluation shouldcan be
performed sooner if it is determined that material changes to System topology or System
operating conditions that could potentially impact the effectiveness or coordination of the RAS
have occurred since the previous RAS evaluation or will occur before the next scheduled
evaluation.. The periodic RAS evaluation will typically lead to one of the following outcomes: 1)
affirmation that the existing RAS is effective; 2) identification of changes needed to the existing
RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.4) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance; consequently, the TP. The PC is the functional entity best
suited to perform the analyses. because they have a wide‐area planning perspective. To
promote reliability, the TPPC is required to provide the RAS‐owner(s) and the reviewing RC(s)
with the results of eachthe evaluation.
to each RAS‐entity and reviewing RC, as well as each impacted Planning Coordinator and
Transmission Planner.
The intent of Requirement R4, Part 4.1.3 is to require that the possible inadvertent operation of
the RAS, (other than limited impact RAS), caused by the malfunction of a single component of
the RAS, meet the same System performance requirements as those required for the
Contingency(ies) or System conditions for which it is designed. If the RAS is designed to meet
one of the planning events (P0‐P7) in TPL‐001‐4, the possible inadvertent operation of the RAS
must meet the same performance requirements listed in the standard for that planning event.
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The requirement clarifies that the inadvertent operation to be considered is only that caused by
the malfunction of a single RAS component. This allows features to be designed into the RAS to
improve security, such that inadvertent operation due to malfunction of a single component is
prevented or else; otherwise, the RAS inadvertent operation satisfiesmust satisfy Requirement
R4, Part 4.1.3.
The intent of Requirement R4, Part 4.1.3 is also to require that the possible inadvertent
operation of the RAS (other than limited impact RAS) installed for an extreme event in TPL‐001‐
4 or for some other Contingency or System conditions not defined in TPL‐001‐4 (therefore
without performance requirements), meet the minimum System performance requirements of
Category P7 in Table 1 of NERC Reliability Standard TPL‐001‐4. However, instead of referring to
the TPL standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.3.1 – 4.1.3.5) are the ones that are common to all planning events (P0‐P7) listed in
TPL‐001‐4.
With reference to Requirement 4, Part 4.1.3, note that the only differences in performance
requirements among the TPL (P0‐P7) events (not common to all of them) concern Non‐
Consequential Load Loss and interruption of Firm Transmission Service. PerformanceIt is not
necessary for Requirement R4, Part 4.1.3 to specify performance requirements inrelated to
these areas are not relevant. Abecause a RAS is only allowed to drop non‐consequential load or
interrupt Firm Transmission Service can do that only if that action is allowed for the
Contingency for which it is designed. Therefore, the inadvertent operation should automatically
meet Non‐Consequential Load Loss or interrupting Firm Transmission Service performance
requirements for the Contingency(ies) for which it was designed.
Part 4.1.4 requires that a single component failure in the RAS, (other than limited impact RAS),
when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. This analysis is needed to
ensure that changing System conditions do not result in the single component failure
requirement not being met.
Requirements for inadvertent RAS operation (Requirement R4, Part 4.1.3) and single
component failure (Requirement R4, Part 4.1.4) are reviewed by the reviewing RC(s) before a
new or functionally modified RAS is placed in ‐service, and are typically satisfied by specific
design considerations. Although the scope of the periodic evaluation does not include a new
design review, it is possible that a design which previously satisfied requirements for
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inadvertent RAS operation and single component failure may fail to satisfy these requirements
at a later point in time, and must be evaluated with respect to the current System. For example,
if the actions of a particular RAS include tripping load, System changesload growth could occur
over time that impactimpacts the amount of load originallyto be tripped by a particular RAS
output.. These changes could result in inadvertent activation of that output, therefore, tripping
too much load upon inadvertent operation and result in violations of Facility Ratings.
Alternatively, the RAS might be designed to trip more load than necessary (i.e., “over trip”) in
order to satisfy single‐ component‐ failure requirements. System changes could result in too
little load being tripped at affected locations and result inand unacceptable BES performance if
one of the loads failed to trip.
Requirement R5
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120‐ full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4 regarding
the investigation of a Protection System Misoperation.; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
the RAS‐ownerentity(s) is required to provide the results of RAS operational performance
analyses to its reviewing RC(s).
The RAS‐owner(sentity(ies) may need to collaborate with theirits associated TPTransmission
Planner to comprehensively analyze RAS operational performance. This is because a RAS
operational performance analysis involves verifying that the RAS operation triggers and
responds (Partswas triggered correctly (Part 5.1,.1), responded as designed (Part 5.1.2)), and
that the resulting BES response (Parts 5.1.3, and 5.1.4) iswas consistent with the intended
functionality and design of the RAS. Ideally, when there is more than one RAS‐entity for a RAS,
the RAS‐entities would collaborate on the operational performance analysis.
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Requirement R6
Deficiencies RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may
be identified either in the periodic RAS evaluation conducted by the TPPC in Requirement R4, or
in the operational analysis conducted by the RAS‐owner(s) pursuant to entity in Requirement
R5, are likely to pose a reliability risk to the BES. or in the functional test performed by the RAS‐
entity(ies) in Requirement R8. To mitigate thispotential reliability riskrisks, Requirement R6
mandates that each RAS‐owner develop entity participate in developing a CAP that establishes
the mitigation actions and timetable necessary to address the deficiency.
The RAS‐entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS‐entity(ies) may request assistance with development of the
CAP requires that afrom other parties such as its Transmission Planner or Planning Coordinator;
however, the RAS‐entity has the responsibility for compliance with this requirement.
A CAP may require functional changechanges be made to a RAS. In this case, Attachment 1
information must be submitted to the reviewing RC(s) prior), an RC review must be performed
to placingobtain RC approval before the RAS‐entity can place RAS modifications in ‐service, per
RequirementRequirements R1.
, R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering, or consulting work. A timeframe of six‐ full‐ calendar months is allotted to allow
enough time for RAS‐ownerentity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. A RAS deficiency may require the RC or
Transmission Operator to impose operating restrictions so the System can operate in a reliable
way until the RAS deficiency is resolved. SuchThe possibility of such operating restrictions will
incent the RAS‐ownerentity to resolve the issue as quickly as possible.
A CAP documents a RAS performance deficiency, the actions to correct the deficiency with
identified tasks, and the time frame for completion.
The following are example situations of when a CAP is required:
A determination after a RAS operation/non‐operation investigation that the RAS did not
meet performance expectations. The RAS or did not operate as designed.
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
Equipment failures.
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
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Implementation of a CAP ensuresRequirement R7 mandates that each RAS‐entity implement its
CAP developed in Requirement R6 which mitigates the deficiencies are corrected by following a
documented timetable of identified in Requirements R4, R5, or R8. By definition, a CAP is: “A
list of actions. If necessary, the and an associated timetable for implementation to remedy a
specific problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. Operating restrictions imposed by the RC If the CAP is changed, the RAS‐
entity must notify the reviewing Reliability Coordinator(s). The RAS‐entity must also incents
RAS‐owners to mitigate the issues and provide assurance that implementation is notify the
Reliability Coordinator(s) when the CAP has been completed.
The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS‐entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non‐Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in‐service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC‐005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed withoutwith minimum
impact to the BES and should align with expected results. The RAS‐ownerentity is in the best
position to determine the testing procedure and schedule due to their overall knowledge of the
RAS design, installation, and functionality. Periodic testing provides the RAS‐ownerentity
assurance that latent failures may be identified and also promotes identification of changes in
the System that may have introduced latent failures.
While the
The six‐ and twelve full calendar‐ year functional testing interval isintervals are greater than the
annual or bi‐annual periodic testing performed in some NERC Regions, the drafting team
selected it because it is consistent with some of the maintenance intervals of various Protection
System and Automatic Reclosing components established in PRC‐005. Consequently, this
interval provides entities the opportunity to design their RAS functional testing programs such
that it coincides with the testing of any associated PRC‐005 components. The six‐calendar‐year
interval is. However, these intervals are a balance between the resources required to perform
the testing and the potential reliability impacts to the BES created by undiscovered latent
failures that could cause an incorrect operation of the RAS.
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Longer test intervals for limited impact RAS are acceptable because incorrect operations or
failures to operate present a low reliability risk to the Bulk Power System.
Functional testing is not synonymous with end‐to‐end testing. End‐to‐end testing is an
acceptable method but it may not be feasible for many RAS. When end‐to‐end testing is not
possible, a RAS‐ownerentity may use a segmented functional testing approach. The segments
can be tested individually negating the need for complex maintenance schedules. In addition,
actual RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does
not operate in its entirety during a System event or System conditions do not allow an end‐to‐
end systemscheme test—the,, then the segmented approach should be used to fulfill this
Requirement. Functional testing includes the testing of all RAS inputs used for detection,
arming, operating, and data collection. Functional testing also includes the processing by the
logic and infrastructure of a RAS as well as the action initiation by RAS outputs to address the
System condition(s) for which the RAS is designed. All segments and components of a RAS must
be tested or have proven operations within a six‐calendar‐year interval to demonstrate
compliance with the Requirement.
As an example, consider a RAS implemented with one PLC that senses System conditions such
as loading and line status from many locations. At one of these locations, a line protective relay
(a component of a Protection System and included in the Protection System Maintenance
Program (PSMP) of a RAS‐owner) receives commands from the RAS PLC and sends data over
non‐Protection System communications infrastructure to operate a breaker. A functional test
would send signals of simulated System conditions to the PLC to initiate an operate command
to the protective relay, thus operating its associated breaker. This action verifies RAS action,
verifies PLC control logic, and verifies RAS communications from PLC to relay. To complete this
portion of a functional test, application of external testing signals to the protective relay,
verified at the PLC are necessary to confirm full functioning of the RAS segment being tested.
This example describes a test for one segment of the RAS, the remaining segments would also
require testingthe applicable maximum test interval to demonstrate compliance with the
Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC‐005, Table 1‐1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up‐to the protective
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relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3‐8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well‐defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component‐level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of contingenciesContingencies, and to verify scheme performance as well as the inputs and
outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real‐time) to
the Transmission Operator via PRC‐001, Requirement R6, then to the RC via TOP‐001‐2,
Requirement R5.3, Requirement R8. See Phase 2 of Project 2007‐06 for the mapping document
from PRC‐001 to other standards regarding notification of RC by TOP if a deficiency is found
during testing. Consequently, it is not necessary to include a similar requirement in this
standard.
The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end‐to‐end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS‐entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
maximum test interval that started on the date of the previous successful test of those (non‐
operating) segments in order to be compliant with Requirement R8.
Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available to entities with a potential reliability need. Attachment 3
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contains the minimum information that is required to be included about each RAS listed in the
database. Additional information can be requested by the RC.
The information provided is sufficient for an entity with a reliability need to evaluate whether
the RAS can impact its System. For example, a RAS performing generation rejection to mitigate
an overload on a transmission line may cause a power flow change within an adjacent entity
area. This entity should be able to evaluate the risk that a RAS poses to its System from the
high‐level information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS‐entity from the RC.
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Process Flow Diagram
The following diagrams depictdiagram below depicts the process flow of the PRC‐012‐2
requirements.
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS‐owner(sentity(ies) to provide a detailed list of
information describing the RAS to the designated RAS‐entity.reviewing RC. If there are multiple
owners of theRAS‐entities for a single RAS, information maywill be needed from all owners, but
a single RAS‐owner (designated as the entities. Ideally, in such cases, a single RAS‐entity) is
assigned will take the responsibility of compilinglead to compile all the RAS data and presenting
it to the reviewing RC(s). Other RAS‐owners may participate in the review, if they choose.
identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide‐ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified7 RAS that the RAS‐entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS‐entity
provides a summary of the previously approvedexisting RAS functionality.
I.
General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single‐line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
7
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond thein‐kind replacement of existing components that preserve the original
functionality is a functional modification.
•
Changes to RAS logic beyond error correcting
•
Changes to redundancy levels; i.e., addition or removal
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associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
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3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012‐2, Requirements R5 and R7]
Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, or the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name
b. Each RAS‐entity and contact information
c. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date;
most recent 60‐ full‐ calendar‐ month (Requirement R4) evaluation date; and, date
of retirement, if applicable
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery)
e. Description of the contingenciesContingencies or System conditions for which the
RAS was designed (initiating conditions)
f. Corrective action taken by the RAS
g. Identification of limited impact8 RAS
g.h.
Any additional explanation relevant to high level understanding of the RAS
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II.
Functional Description and Transmission Planning Information
1. Contingencies and system conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
8
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact.
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a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical system
contingenciesSystem Contingencies or other operating conditions when RAS action
is intended to occur. If no arming conditions are required, this should also be stated.
c. Event‐based RAS are triggered by specific contingenciesContingencies that initiate
mitigating action. Condition‐based RAS may also be initiated by specific
contingenciesContingencies, but specific Contingencies are not always required.
These triggering Contingencies and/or conditions should be identified.
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2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), systemSystem conditions, and
contingenciesContingencies analyzed on which the RAS design is based, and when those
technical studies were performed. [Reference NEC Reliability Standard PRC‐014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS‐related operations.
4. Information regarding any future system plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. Documentation showing that the possible inadvertent operation of the RAS resulting
from any single RAS component malfunction satisfies all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
5. RAS‐entity proposed designation as “limited impact” or not.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in
WECC will be recognized as limited impact for the purposes of Requirement 4, Parts
4.1.3 and 4.1.4.
a. The BES shall remain stable.
b.a.
Cascading shall not occur.
c.a. Applicable Facility Ratings shall not be exceeded.
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d.a. BES voltages shall be within post‐Contingency voltage limits and post‐
Contingency voltage deviation limits as established by the Transmission Planner and
the Planning Coordinator.
e.a.Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
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6. Documentation showing that the possible inadvertent operation of the RAS resulting
from any single RAS component malfunction satisfies all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
6.7.
An evaluation indicating that the RAS settings and operation avoids adverse
interactions with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or re‐
configuring the systemSystem. Many RAS depend on sensing specific System
configurations to determine whether they need to arm or take actions. An examples of
an adverse interaction: A RAS that reconfigures the System also changes the available
fault duty, which can affect distance relay overcurrent (“fault detector”) supervision and
ground overcurrent protection coordination.
7.8.
Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection,
telecommunications, transfer tripdc supply, communications, logic processing, control
actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be designed
to be secure. Several types of devices have been commonly used as disturbance, condition,
or status detectors:
Line open status (event detectors),
Protective relay inputs and outputs (event and parameter detectors),
Transducer and IED (analog) inputs (parameter and response detectors),
Rate of change (parameter and response detectors).
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DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by PRC‐
005. However, redundant RAS systems, when used, should be supplied from separately
protected (fused or breakered) circuits.
Communications: Telecommunications Channels and Transfer Trip Equipment
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non‐deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel or
equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS‐ownerentity, or
perhaps leased from another entity familiar with the necessary reliability requirements. All
channel equipment should be monitored and alarmed to the dispatch center so that timely
diagnostic and repair action shall take place upon failure. Publicly switched telephone
networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel working
on the channel can readily identify the proper circuit. Channels between entities should be
identified with a common name at all terminals.
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions may
be required at different arming levels or for different contingencies. Contingencies. Scheme
logic may be achievable by something as simple as wiring a few auxiliary relay contacts or by
much more complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units (RTUs),
and logic processors. Single‐function relays have been used historically to implement RAS,
but this approach is now less common except for very simple new RAS or minor additions to
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existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS actions
at the sites where action is required.
Monitoring by SCADA/EMS should include at least
Whether the scheme is in‐service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in‐service or out of service.
For RAS that are armed automatically, these two states are independent because a
RAS that has been placed in ‐service may be armed or unarmed based on whether
the automatic arming criteria have been met.
The current operational state of the scheme (available or not).
In cases where the RAS requires single‐ component failure performance (; e.g.,
redundancy),, the minimal status indications should be provided separately for each
system.
The minimum status is generally sufficient for operational purposes; however,
where possible it may beis often useful to provide additional information regarding
partial failures or the status of critical components to allow the RAS‐ownerentity to
more efficiently troubleshoot a reported failure. Whether this capability exists will
depend in part on the design and vintage of equipment used in the RAS. While all
schemes should provide the minimum level of monitoring, new schemes should be
designed with the objective of providing monitoring at least similar to what is
provided for microprocessor‐based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line‐charging current;
c. Breaker trip coil current monitoring—typically used when high‐speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
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d. Other detectors such as angle, voltage, power, frequency, rate of change of thesethe
aforementioned, out of step, etc.—very. are dependent on specific scheme
requirements, but some forms may substitute for or enhance currentother
monitoring detectiondescribed in items ‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in ‐service or is being
maintained.
In this context, a multifunction device (e.g., microprocessor‐based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor‐based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi‐function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
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4. Documentation showing that describing the System performance resulting from a
single‐ component failure in athe RAS, except for limited impact RAS, when the RAS is
intended to operate, does. A single component failure in a RAS not determined to be
limited impact must not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. The
documentation should describe or illustrate how the implementation design achieves
this objective. [Reference NERC Reliability Standard PRC‐012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement. Acceptable methods to achieve this objective
include, but are not limited to the following:
Acceptable methods to achieve this objective include the following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
Protective or auxiliary relays used by the RAS.
ii.
Communications systems necessary for correct operation of the RAS.
iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Computers or programmable logic devices used to analyze information and
provide RAS operational output.
vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation would not be an issue, ifdue to that single
component failure will still result in satisfactory System performance, as long as
tripping the total armed amount of load or generation does not cause other adverse
impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re‐dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
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IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS‐entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies, if applicable, upon which the decision to retire the RAS
is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent‐wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability‐related considerations generally relevant to various aspects of RAS design
and implementation, and also for the purpose of facilitating consistent reviews continent‐wide
for each RAS to be installed or functionally modified. Most of the checklist items should be
applicable to most RAS. There may be checklist items that are not applicable to a given RAS in
which case they may be noted as not applicable and skipped in the RC review. Depending on
the specifics of the RAS under review, it is possible that other reliability considerations may be
identified during the review. Any other reliability considerations, along with their resolution
with respect to the particular RAS under review, should be documented along with the
Attachment 2 items that were applicable to the specific RAS under review.
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Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
The name used to identify the RAS.
2. Each RAS‐entity and contact information.
A reliable phone number or email address should be included to contact theeach RAS‐
entity if more information is needed. At a minimum, the name of the RAS‐entity
responsible for the RAS information should be provided.
3. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date; most
recent 60‐ full‐ calendar‐ month (Requirement R4) evaluation date; and, date of retirement,
if applicable.
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under‐/over‐voltage, slow voltage
recovery).
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the contingenciesContingencies or System conditions for which the RAS was
designed (initiating conditions).
A high level summary of the conditions/contingenciesContingencies is expected. Not all
combinations of conditions are required to be listed.
6. Corrective action taken by the RAS.
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
7. Identification of limited impact9 RAS.
7.8.
Specify whether or not the RAS is designated as limited impact.
Any additional explanation relevant to high‐level understanding of the RAS.
9
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
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If deemed necessary, any additional information can be included in this section, but is
not mandatory.
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Proposed Definition of “Special Protection System”
Special Protection System (SPS)
Background
In Order No. 693, the Commission approved, among other things, the Glossary of Terms Used in NERC
Reliability Standards (“NERC Glossary”), which included NERC’s currently definitions of Special Protection
System and Remedial Action Scheme. The NERC Glossary currently defines a Special Protection System
as:
An automatic protection system designed to detect abnormal or predetermined system
conditions, and take corrective actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may include changes in demand,
generation (MW and Mvar), or system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load
shedding or (b) fault conditions that must be isolated or (c) out‐of‐step relaying (not designed as
an integral part of an SPS). Also called Remedial Action Scheme.
The currently‐effective NERC Glossary definition for “Remedial Action Scheme” is a cross‐reference to the
definition of Special Protection System and reads: “See ‘Special Protection System.’” This internal cross‐
references from Remedial Action Scheme to Special Protection System in lieu of a separate definition was
developed to ensure that the terms are used interchangeably even where entities or an interconnection
uses one term versus the other.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” to add clarity and to ensure proper identification of Remedial Action Schemes and a more
consistent application of related Reliability Standards. As explained in the petition, “[t]he defined terms
‘Special Protection System’ and ‘Remedial Action Scheme’ are currently used interchangeably throughout
the NERC Regions and in various Reliability Standards, including prior versions of the Proposed Reliability
Standards.” Along with this proposed revised definition, NERC submitted revisions to various Reliability
Standards by replacing the term “Special Protection System” and replacing it with the newly revised
“Remedial Action Scheme.” As NERC stated, “use of only one term in the NERC Reliability Standards will
ensure proper identification of these systems and application of related Reliability Standards.” The
petition also anticipated future revision to the definition of “Special Protection System” to cross‐reference
the newly revised and proposed definition of “Remedial Action Scheme.” This coordination, which would
be achieved by implementing the new definition of “Special Protection System” simultaneously with the
Commission approval of the revised definition for “Remedial Action Scheme,” will ensure that all
references to “Special Protection System” and “Remedial Action Scheme” refer to the same revised
definition.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards.
Proposed Definition
Special Protection System (SPS)
See “Remedial Action Scheme”
Proposed Definition of “Special Protection System” (SPS) | November 2015
2
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
PRC‐012‐2 – Remedial Action Schemes
Requested Retirements
PRC‐012‐1 – Remedial Action Scheme Review Procedure
PRC‐013‐1 – Remedial Action Scheme Database
PRC‐014‐1 – Remedial Action Scheme Assessment
PRC‐015‐1 – Remedial Action Scheme Data and Documentation
PRC‐016‐1 – Remedial Action Scheme Misoperations
Applicable Entities
Reliability Coordinator
Planning Coordinator
RAS‐entity – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or
part of a RAS
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for Remedial
Action Scheme (“RAS”) and associated revisions to related Reliability Standards to consolidate that term
with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not
enforceable, NERC revised these standards to account for the RAS definition revision and changed
relevant version numbers to reflect the change. Because of this change, NERC requested retirement of
PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0, and provided, for informational purposes only, updated
Reliability Standards PRC‐012‐1, PRC‐013‐1, and PRC‐014‐1. In the same Petition, NERC requested
retirement of PRC‐015‐0 and PRC‐016‐0.1 and approval of Reliability Standards PRC‐015‐1 and PRC‐016‐
1, again implementing changes stemming from the revised definition of RAS.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the
Commission issued a Final Order approving the RAS definition and associated standards.
General Considerations
Reliability Standard PRC‐012‐2 was developed to consolidate previously unapproved standards which
were designated by the Commission as “fill‐in‐the‐blank” standards and to revise other RAS‐related
standards. Reliability Standard PRC‐012‐2 also provides clear and unambiguous responsibilities to the
specific users, owners, and operators of the Bulk‐Power System. Reliability Standard PRC‐012‐2
establishes a new working framework between RAS‐entities, PCs, and RCs, and this new framework will
involve considerable start‐up effort. As such, implementation of Reliability Standard PRC‐012‐2 will occur
over a thirty six (36) month period after approval of the standard by applicable governmental authorities.
Effective Date
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐012‐2
shall become effective on the first day of the first calendar quarter that is thirty six (36) months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Provisions concerning the initial performance of
obligations under Requirements R4, R8, and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is thirty six (36) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Provisions concerning the initial performance of obligations under Requirements R4, R8, and R9 are
outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within sixty
(60) full calendar months of the effective date of PRC‐012‐2, as described above. For new or functionally
modified RAS, the initial performance of Requirement R4 must be completed within sixty (60) full calendar
months of the date that the RAS is approved by the reviewing RC(s) under Requirement R3.
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years of the effective date for PRC‐012‐2, as
described above. For each RAS designated as limited impact, initial performance of obligations under
Requirement R8 must be completed at least once within twelve (12) full calendar years of the effective
date for PRC‐012‐2, as described above.
Requirement R9
For each Reliability Coordinator that does not have a RAS database upon the effective date of PRC‐012‐2,
as described above, the initial obligation under Requirement R9 is to establish a database.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
November 2015
Page 2 of 3
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the effective date of PRC‐
012‐2 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
November 2015
Page 3 of 3
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
PRC‐012‐2 – Remedial Action Schemes
Requested Retirements of Reliability Standards1
PRC‐012‐0 – Special Protection System1 – Remedial Action Scheme Review Procedure
PRC‐013‐0 – Special Protection System Database
PRC‐014‐0 – Special Protection System Assessment
PRC‐012‐1 – Special Protection System Review Procedure
PRC‐013‐1 – Special Protection SystemRemedial Action Scheme Database
PRC‐014‐1 – Special Protection SystemRemedial Action Scheme Assessment
PRC‐015‐0 – Special Protection System1 – Remedial Action Scheme Data and Documentation
PRC‐016‐0.1 – Special Protection SystemRemedial Action Scheme Misoperations
PRC‐015‐1 – Special Protection System Data and Documentation
PRC‐016‐1 – Special Protection System Misoperations
Prerequisite Approval
Revised definition of “Remedial Action Scheme”
Applicable Entities
Reliability Coordinator
Transmission Planner
Planning Coordinator
RAS‐ownerentity – the Transmission Owner, Generator Owner, or Distribution Provider that owns
all or part of a RAS
RAS‐entity – the RAS‐owner designated to represent all RAS‐owner(s) for coordinating the review and
approval of a RAS
1
Retirement includes withdrawal of pending Reliability Standards.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
AugustNovember 2015
Page 2 of 5
General Considerations
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for
RASRemedial Action Scheme (“RAS”) and associated revisions to related Reliability Standards to
consolidate that term with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not
enforceable, NERC revised these standards to account for the RAS definition revision and changed
relevant version numbers to reflect the change. Because of this change, NERC requested retirement of
PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0, and provided, for informational purposes only, updated
Reliability Standards PRC‐012‐1, PRC‐013‐1, and PRC‐014‐1. In the same Petition, NERC requested
retirement of PRC‐015‐0 and PRC‐016‐0.1 and approval of Reliability Standards PRC‐015‐1 and PRC‐016‐
1 and retirement of PRC‐015‐0 and PRC‐016‐0.1, again implementing changes stemming from the revised
definition of RAS.
TheOn June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to
accept the revisions to the RAS definition and associated standards, and on June 18, 2015. As of the date
of posting of this Implementation Plan, howeverNovember 19, 2015, the Commission has not issued ana
Final Order approving the RAS definition and associated standards.
General Considerations
retirement the Reliability Standards enumerated above. BecauseStandard PRC‐012‐2 was developed to
consolidate previously unapproved standards which were designated by the Commission as “fill‐in‐the‐
blank” standards and to revise other RAS‐related standards. Reliability Standard PRC‐012‐2 also provides
clear and unambiguous responsibilities to the specific users, owners, and operators of the Bulk‐Power
System. Reliability Standard PRC‐012‐2 establishes a new working framework between RAS‐entities, PCs,
and RCs, and this new framework will involve considerable start‐up effort. As such, implementation of
Reliability Standard PRC‐012‐2 will occur over a thirty six (36) month period after approval of the
standard drafting team for this project has determined that the retirements requested above are
necessary to ensure a seamless transition to consolidation of these standards in PRC‐012‐2, NERC
reiterates the requests for retirements already submitted in the Petition and those that are still pending
at the Commissionby applicable governmental authorities.
Effective Dates for PRC-012-2Date
The proposedWhere approval by an applicable governmental authority is required, Reliability Standard
PRC‐012‐2 shall become effective on the later of the day after the revised definition of Remedial Acton
Scheme becomes effective or the first day of the first calendar quarter that is twelve (12thirty six (36)
months after the dateeffective date of the applicable governmental authority’s order approving the
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
AugustNovember 2015
Page 3 of 5
standard is approved by an applicable governmental authority, or as otherwise provided for in a
jurisdiction where approval by anthe applicable governmental authority is required for a standard to go
into effect. . Provisions concerning the initial performance of obligations under Requirements R4, R8,
and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is twelve (12thirty six (36) months after the
date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction. Provisions concerning the initial performance of obligations under Requirements R4, R8, and
R9 are outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within sixty
(60) full calendar months of the effective date of PRC‐012‐2, as described above. For new or functionally
modified RAS, the initial performance of Requirement R4 must be completed within sixty (60) full calendar
months of the date that the RAS is approved by the reviewing RC(s) under Requirement R3.
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years of the effective date for PRC‐012‐2, as
described above. For each RAS designated as limited impact, initial performance of obligations under
Requirement R8 must be completed at least once within twelve (12) full calendar years of the effective
date for PRC‐012‐2, as described above.
Requirement R9
For each Reliability Coordinator that does not have a RAS database upon the effective date of PRC‐012‐2,
as described above, the initial obligation under Requirement R9 is to establish a database.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
AugustNovember 2015
Page 4 of 5
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the Effective Dateeffective
date of PRC‐012‐2 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
AugustNovember 2015
Page 5 of 5
Implementation Plan for the Revised
Definition of “Special Protection System”
Project 2010-05.3 – Remedial Action Scheme (RAS)
Requested Approval
Definition of “Special Protection System”
Requested Retirement
Existing definition of “Special Protection System”
Background
In Order No. 693, the Commission approved, among other things, the Glossary of Terms Used in NERC
Reliability Standards (“NERC Glossary”), which included NERC’s currently definitions of Special
Protection System and Remedial Action Scheme. The NERC Glossary currently defines a Special
Protection System as:
An automatic protection system designed to detect abnormal or predetermined system
conditions, and take corrective actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may include changes in demand,
generation (MW and Mvar), or system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load
shedding or (b) fault conditions that must be isolated or (c) out‐of‐step relaying (not designed as
an integral part of an SPS). Also called Remedial Action Scheme.
The currently‐effective NERC Glossary definition for “Remedial Action Scheme” is a cross‐reference to
the definition of Special Protection System and reads: “See ‘Special Protection System.’” This internal
cross‐references from Remedial Action Scheme to Special Protection System in lieu of a separate
definition was developed to ensure that the terms are used interchangeably even where entities or an
interconnection uses one term versus the other.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” developed by the standard drafting team Project 2010‐05.2 (SPS SDT). As explained in the
petition, “[t]he defined terms ‘Special Protection System’ and ‘Remedial Action Scheme’ are currently
used interchangeably throughout the NERC Regions and in various Reliability Standards, including prior
versions of the Proposed Reliability Standards.” In developing a solution for this inconsistency, the SPS
SDT revised the definition of Remedial Action Scheme to incorporate a higher level of specificity for
schemes that are appropriately considered Remedial Action Schemes, to provide more consistent
identification of Remedial Action Schemes across the NERC Regions, and to state the relationship
between Protection Systems and Remedial Action Schemes. NERC also submitted revisions to various
Implementation Plan for the Revised Definition of “Special Protection System”
Project 2010‐05.3 – Remedial Action Scheme | November 2015
1
Reliability Standards by replacing the term “Special Protection System” with the newly revised “Remedial
Action Scheme.” As NERC stated, the “use of only one term in the NERC Reliability Standards will ensure
proper identification of these systems and application of related Reliability Standards.”
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to
accept the revisions to the RAS definition and associated standards, and on November 19, 2015, the
Commission issued a Final Order approving the RAS definition and associated standards.
General Considerations
The petition for revisions to the Definition of “Remedial Action Scheme” and related Reliability
Standards also anticipated revision of the definition of “Special Protection System” to cross‐reference
the newly revised definition of “Remedial Action Scheme.” Coordination of the two terms was
completed by the SPS SDT in this phase of the Project (Project 2010‐05.3) and will implement the new
definition of “Special Protection System” simultaneously with the effective date of the revised definition
for “Remedial Action Scheme.” By assigning simultaneous effective dates of the revised definition of
“Special Protection System” and “Remedial Action Scheme,” all references to either term in NERC or
Regional Entity documents will refer to the same NERC Glossary definition.
Effective Dates
Where approval by an applicable governmental authority is required, the revised definition of Special
Protection System shall become effective on the later of the effective date of the applicable
governmental authority’s order approving the revised definition of Special Protection System or the
effective date of the revised definition of Remedial Action Scheme approved by the Commission on
November 19, 2015.
Where approval by an applicable governmental authority is not required, the revised definition of
Special Protection System shall become effective on the later of the day that it is adopted by the NERC
Board of Trustees, or as otherwise provided for in that jurisdiction, or the effective date of the revised
definition of Remedial Action Scheme approved by the Commission on November 19, 2015.
Implementation Plan for the Revised Definition of “Special Protection System”
Project 2010‐05.3 – Remedial Action Scheme | November 2015
2
Unofficial Comment Form
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2 and Proposed Definition of “Special Protection
System”
Do not use this form for submitting comments. Use the electronic form to submit comments on draft 2 of
PRC-012-2 – Remedial Action Schemes and the Proposed Definition of “Special Protection System”. The
electronic comment form must be submitted by 8 p.m. Eastern, Friday, January 8, 2016.
Documents and information about this project are available on the project page. If you have questions,
contact Standards Developer, Al McMeekin (via email), or at (404) 446-9675.
Background Information
This project is addressing all aspects of Remedial Action Schemes (RAS) and Special Protection Systems
(SPS) contained in the RAS/SPS-related Reliability Standards: PRC-012-1, PRC-013-1, PRC-014-1, PRC-0151, and PRC-016-1. The maintenance of the Protection System components associated with RAS (PRC-0171 Remedial Action Scheme Maintenance and Testing) are already addressed in PRC-005. PRC-012-2
addresses the testing of the non-Protection System components associated with RAS/SPS and the overall
performance of the RAS.
In FERC Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and
PRC-014-0 as “fill-in-the-blank” standards and did not approve or remand them. These standards are
applicable to the Regional Reliability Organizations (RROs), assigning the RROs the responsibility to
establish regional procedures and databases, and to assess and document the operation, coordination,
and compliance of RAS/SPS. The deference to regional practices precludes the consistent application of
RAS/SPS-related Reliability Standard requirements.
The proposed draft of PRC-012-2 corrects the applicability of the fill-in-the-blank standards by assigning
the requirement responsibilities to the specific users, owners, and operators of the Bulk-Power System;
and incorporates the reliability objectives of all the RAS/SPS-related standards.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” to add clarity and to ensure proper identification of Remedial Action Schemes and a more
consistent application of related Reliability Standards. As explained in the petition, “[t]he defined terms
‘Special Protection System’ and ‘Remedial Action Scheme’ are currently used interchangeably throughout
the NERC Regions and in various Reliability Standards, including prior versions of the Proposed Reliability
Standards.” Along with this proposed revised definition, NERC submitted revisions to various Reliability
Standards by replacing the term “Special Protection System” and replacing it with the newly revised
“Remedial Action Scheme.” As NERC stated, “use of only one term in the NERC Reliability Standards will
ensure proper identification of these systems and application of related Reliability Standards.” The
petition also anticipated future revision to the definition of “Special Protection System” to cross-reference
the newly revised and proposed definition of “Remedial Action Scheme.” This coordination, which would
be achieved by implementing the new definition of “Special Protection System” simultaneously with the
Commission approval of the revised definition for “Remedial Action Scheme,” will ensure that all
references to “Special Protection System” and “Remedial Action Scheme” refer to the same revised
definition. On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”)
proposing to accept the revisions to the RAS definition and associated standards, and on November 19,
2015, the Commission issued a Final Order approving the RAS definition and associated standards.
45-day Formal Comment Period
The drafting team made numerous changes to Reliability Standard PRC-012-2 and its implementation plan
based on stakeholder comments from the previous posting. The team appreciates the feedback you
provided and considered all of your suggestions. The responses to your comments and a summary of the
changes are located in the Consideration of Comments document posted on the project page. The
drafting team is soliciting stakeholder comments and feedback on the second draft of PRC-012-2 and its
implementation plan.
Additionally, the drafting team is soliciting comments and feedback on the revised definition of “Special
Protection System” and its implementation plan which are posted for an initial ballot.
Unofficial Comment Form | PRC-012-2 and Proposed Definition of “Special Protection System”
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS) | November 2015
2
Questions
1. Limited impact designation: Within the RAS review process of PRC-012-2, the drafting team included
a provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent operation
or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A RAS
implemented prior to the effective date of this standard that has been through the regional review
process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact. When appropriate, new or functionally modified RAS implemented after the effective
date of this standard will be designated as limited impact by the Reliability Coordinator during the RAS
review process. Do you agree with the provision that RAS can be designated as “limited impact”? If no,
please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
2. Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to provide
clarity and to lengthen the implementation period to thirty-six months to provide the responsible
entities adequate time to establish the new working frameworks among functional entities. Do you
agree with the revised Implementation Plan? If no, please provide the basis for your disagreement and
an alternate proposal.
Yes
No
Comments:
3. Revised Definition of “Special Protection System” and its Implementation Plan: The drafting team
revised the definition of “Special Protection System” to cross-reference the revised definition of
“Remedial Action Scheme”. The Implementation Plan for the revised definition of “Special Protection
System” aligns with the effective date of the revised definition of “Remedial Action Scheme”. Do you
agree with the proposed definition and its implementation plan? If no, please provide the basis for
your disagreement and an alternate proposal.
Yes
No
Comments:
4. If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Comments:
Unofficial Comment Form | PRC-012-2 and Proposed Definition of “Special Protection System”
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS) | November 2015
3
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
R1.1. Description of the process for submitting a
proposed RAS for Regional Reliability
Organization review.
R1.2. Requirements to provide data that describes
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
shall be designed so that a single RAS
component failure, when the RAS was
intended to operate, does not prevent the
interconnected transmission system from
meeting the performance requirements
defined in Reliability Standards TPL-001-0,
TPL-002-0, and TPL-003-0.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC-012-1 R.1.1:
Covered by Requirements R1,
R2 and R3.
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC-012-1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC-012-1 R.1.3:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4.1.4
PRC-012-1 R.1.4:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2, and
Requirement R4.1.3.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Each Planning Coordinator, at least once every
60 full calendar months, shall:
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was
designed, and not exceed TPL-003-0.
PRC-012-1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4.1.2.
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
R1.5. Requirements to demonstrate the proposed
RAS will coordinate with other protection
and control systems and applicable Regional
Reliability Organization Emergency
procedures.
PRC-012-1 R.1.6:
Covered by Requirement R5
Existing Requirement in Reliability Standard
R1.6. Regional Reliability Organization definition
of misoperation.
R1.7. Requirements for analysis and
documentation of corrective action plans for
all RAS misoperations.
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
PRC-012-1 R.1.7:
Covered by Requirements R4
and R6
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.3.1 The BES shall remain stable.
PRC-012-1 R.1.8:
PRC-012-2 NERC Standards
Development Process
4.1.3.2 Cascading shall not occur.
PRC-012-1 R.1.9:
Covered by Requirement R8
4.1.3.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator pursuant to
Requirements R5, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS-entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
performance and the proper operation of non-Protection
System components:
•
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
At least once every six full calendar years for all
RAS not designated as limited impact, or
4
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
Translation to New
Standard or Other Action
PRC-013-1 R1:
Covered by Requirement R9
PRC-013-1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
PRC-014-1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Each Planning Coordinator, at least once every
60 full calendar months, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.3 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.4 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
PRC-014-1 R2:
Covered by Requirement R4
R4. Each Each Planning Coordinator, at least once every
60 full calendar months, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.3.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.4 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
PRC-014-1 R3:
Covered by Requirement R4
R4. Each Each Planning Coordinator, at least once every
60 full calendar months, shall:
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R3.1. Identification of group conducting the assessment
and the date the assessment was performed.
R3.2. Study years, system conditions, and contingencies
analyzed in the technical studies on which the
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non-compliant
RAS.
Translation to New
Standard or Other Action
PRC-014-1 R3.1 - R3.4:
Covered by Requirement R4
PRC-014-1 R3.5:
Covered by Requirement R6
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator pursuant to
Requirements R5, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
11
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall maintain
a list of and provide data for existing and proposed
RAS as specified in Reliability Standard PRC-013-1
R1.
PRC-015-1 R1:
Covered by Requirement R1,
Attachment 1.
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC-012-1_R1 prior to being placed in
service.
PRC-015-1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3.
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
Retired P81
N/A
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
13
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC-012-1_R1.
Translation to New
Standard or Other Action
PRC-016-1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
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Project 2010-05.3 Remedial Action Schemes (RAS)
PRC-016-1 R2:
Covered by Requirements R6
and R7.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator pursuant to
Requirements R5, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
PRC-016-1 R3:
Covered by Requirements R5,
R6, and R7, Attachment 1.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
Mapping Document | November 2015
Project 2010-05.3 Remedial Action Schemes (RAS)
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator pursuant to
Requirements R5, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
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Project 2010-05.3 Remedial Action Schemes (RAS)
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
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Project 2010-05.3 Remedial Action Schemes (RAS)
17
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
Translation to New
Standard or Other Action
PRC‐012‐1 R.1.1:
Covered by Requirements R1,
R2 and R3.
PRC‐012‐1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC‐012‐1 R.1.3:
R1.1. Description of the process for submitting a
Covered by Requirement R1,
proposed RAS for Regional Reliability
Attachments 1, Requirement
Organization review.
R2, Attachment 2 and
R1.2. Requirements to provide data that describes Requirement R4.1.4
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
PRC‐012‐1 R.1.4:
shall be designed so that a single RAS
Covered by Requirement R1,
component failure, when the RAS was
Attachments 1, Requirement
intended to operate, does not prevent the
R2, Attachment 2, and
interconnected transmission system from
Requirement R4.1.3.
meeting the performance requirements
defined in Reliability Standards TPL‐001‐0,
TPL‐002‐0, and TPL‐003‐0.
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. Prior to placing a new or functionally modified RAS in
‐service or retiring an existing RAS, each RAS‐entity shall
submitprovide the information identified in Attachment 1
for review to the Reliability Coordinator(s) that
coordinates the area(s) where the RAS is located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to theeach RAS‐entity.
R3. Following the review performed pursuant to
Requirement R2, the RAS‐entity shall address each
identified issue and obtain approval from each reviewing
Reliability Coordinator, priorPrior to placing a new or
functionally modified RAS in ‐service or retiring an
existing RAS, each RAS‐entity that receives feedback from
the reviewing Reliability Coordinator(s) identifying
reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability
Coordinator.
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL‐
001‐0, TPL‐002‐0, and TPL‐003‐0) as that
required of the contingency for which it was
designed, and not exceed TPL‐003‐0.
Translation to New
Standard or Other Action
PRC‐012‐1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4.1.2.
R1.5. Requirements to demonstrate the proposed PRC‐012‐1 R.1.6:
Covered by Requirement R5
RAS will coordinate with other protection
and control systems and applicable Regional
PRC‐012‐1 R.1.7:
Reliability Organization Emergency
Covered by Requirements R4
procedures.
and R6
R1.6. Regional Reliability Organization definition
of misoperation.
PRC‐012‐1 R.1.8:
PRC‐012‐2 NERC Standards
R1.7. Requirements for analysis and
documentation of corrective action plans for Development Process
all RAS misoperations.
PRC‐012‐1 R.1.9:
R1.8. Identification of the Regional Reliability
Covered by Requirement R8
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
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Project 2010‐05.3 Remedial Action Schemes (RAS)
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Each Planning Coordinator, at least once every
60 full calendar months, shall:
4.1 PerformR4. Each Transmission Planner shall perform
an evaluation of each RAS within its planning area at least
once every 60 full calendar months and provide the RAS‐
owner(s) and the reviewing Reliability Coordinator(s) the
results including any identified deficiencies. Each
evaluation shallto determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 The Except for “limited impact” RAS, the
possible inadvertent operation of the RAS, resulting
from any single RAS component malfunction satisfies
all of the following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.4 AExcept for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate, does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS‐entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS‐owner shallentity, within 120‐ full calendar
days of a RAS operation or a failure of aits RAS to operate
when expected, analyze the RAS performance and
provide the results of the analysis, including any
identified deficiencies, toor on a mutually agreed upon
schedule with its reviewing Reliability Coordinator(s). The
RAS), shall:
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Project 2010‐05.3 Remedial Action Schemes (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1 Participate in analyzing the RAS operational
performance analysis shall to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐owner5.2 Provide the
results of RAS operational performance analysis that
identified any deficiencies to its reviewing Reliability
Coordinator(s).
R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s).) within six full
calendar months of:
R8. At least once every six calendar years, each• Being
notified of a deficiency in its RAS‐owner pursuant to
Requirement R4, or
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Project 2010‐05.3 Remedial Action Schemes (RAS)
4
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
• Notifying the Reliability Coordinator pursuant to
Requirements R5, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS‐entity shall performparticipate in
performing a functional test of each of its RAS to verify
the overall RAS performance and the proper operation of
non‐Protection System components.:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
At least once every six full calendar years for all
RAS not designated as limited impact, or
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
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Project 2010‐05.3 Remedial Action Schemes (RAS)
5
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
PRC‐013‐1 R1:
Covered by Requirement R9
PRC‐013‐1 R1.1:
Covered by Requirement R9,
Attachment 3
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
PRC‐013‐1, R1.2:
designed,
Covered by Requirement R9,
R1.2. Operation — The actions taken by the RAS in Attachment 3
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic PRC‐013‐1, R1.3:
Covered by Requirement R9,
or relay settings that control operation of
Attachment 3
the RAS.
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once eachevery twelve full
calendar yearmonths.
R2. The Regional Reliability Organization shall provide to Retired P81
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
N/A
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Project 2010‐05.3 Remedial Action Schemes (RAS)
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
PRC‐014‐1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Transmission PlannerEach Planning Coordinator,
at least once every 60 full calendar months, shall
perform:
4.1 Perform an evaluation of each RAS within its planning
area at least once every 60 full calendar months and
provide the RAS‐owner(s) and the reviewing Reliability
Coordinator(s) the results including any identified
deficiencies. Each evaluation shallto determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 TheExcept for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
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Project 2010‐05.3 Remedial Action Schemes (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.4 AExcept for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate, does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS‐entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
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Project 2010‐05.3 Remedial Action Schemes (RAS)
PRC‐014‐1 R2:
Covered by Requirement R4
R4. Each Transmission PlannerEach Planning Coordinator,
at least once every 60 full calendar months, shall
perform:
4.1 Perform an evaluation of each RAS within its planning
area at least once every 60 full calendar months and
provide the RAS‐owner(s) and the reviewing Reliability
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Coordinator(s) the results including any identified
deficiencies. Each evaluation shallto determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control
systems.
4.1.3 TheExcept for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component inadvertent
operationmalfunction satisfies all of the following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage
deviation limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
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Project 2010‐05.3 Remedial Action Schemes (RAS)
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.4 AExcept for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate, does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS‐entity, and each
impacted Transmission Planner and Planning
Coordinator.
PRC‐014‐1 R2R3:
Covered by Requirement R4
PRC‐014‐1 R3.1:
R3.1. Identification of group conducting the assessment Covered by Requirement R4
and the date the assessment was performed.
R3.2. Study years, system conditions, and contingencies PRC‐014‐1 R3.2:
Covered by Requirement R4
analyzed in the technical studies on which the
assessment is based and when those technical
PRC‐014‐1 R3.3:
studies were performed.
Covered by Requirement R4
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
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Project 2010‐05.3 Remedial Action Schemes (RAS)
R4. Each Transmission PlannerEach Planning Coordinator,
at least once every 60 full calendar months, shall
perform:
4.1 Perform an evaluation of each RAS within its planning
area at least once every 60 full calendar months and
provide the RAS‐owner(s) and the reviewing Reliability
Coordinator(s) the results including any identified
deficiencies. Each evaluation shallto determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non‐compliant
RAS.
PRC‐014‐1 ‐ R3.4:
Covered by Requirement R4
PRC‐014‐1 R3.5:
Covered by Requirement R6
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 TheExcept for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component inadvertent operation
malfunction satisfies all of the following:
4.1.3.1 The BES shall remain stable.
4.1.3.2 Cascading shall not occur.
4.1.3.3 Applicable Facility Ratings shall not be
exceeded.
4.1.3.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.3.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.4 AExcept for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate, does not prevent the BES from
meeting the same performance requirements
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Project 2010‐05.3 Remedial Action Schemes (RAS)
11
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐owner4.2 Provide the results
of the RAS evaluation including any identified deficiencies
to each reviewing Reliability Coordinator and RAS‐entity,
and each impacted Transmission Planner and Planning
Coordinator.
R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s).) within six full
calendar months of:
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
• Notifying the Reliability Coordinator pursuant to
Requirements R5, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
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Project 2010‐05.3 Remedial Action Schemes (RAS)
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
PRC‐015‐1 R1:
Distribution Provider that owns a RAS shall maintain Covered by Requirement R1,
a list of and provide data for existing and proposed Attachment 1.
RAS as specified in Reliability Standard PRC‐013‐1
R1.
R1. Prior to placing a new or functionally modified RAS in
‐service or retiring an existing RAS, each RAS‐entity shall
submitprovide the information identified in Attachment 1
for review to the Reliability Coordinator(s) that
coordinates the area(s) where the RAS is located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC‐012‐1_R1 prior to being placed in
service.
R1. Prior to placing a new or functionally modified RAS in
‐service or retiring an existing RAS, each RAS‐entity shall
submitprovide the information identified in Attachment 1
for review to the Reliability Coordinator(s) that
coordinates the area(s) where the RAS is located.
PRC‐015‐1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to theeach RAS‐entity.
R3. Following the review performed pursuant to
Requirement R2, the RAS‐entity shall address each
identified issue and obtain approval from each reviewing
Reliability Coordinator, priorPrior to placing a new or
functionally modified RAS in ‐service or retiring an
existing RAS, each RAS‐entity that receives feedback from
the reviewing Reliability Coordinator(s) identifying
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Project 2010‐05.3 Remedial Action Schemes (RAS)
13
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
issue(s) shall resolve each issue to obtain approval of the
RAS from each reviewing Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Retired P81
Distribution Provider that owns a RAS shall provide
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
N/A
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Project 2010‐05.3 Remedial Action Schemes (RAS)
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC‐012‐1_R1.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC‐016‐1 R1:
Covered by Requirement R5
R5. Each RAS‐owner shallentity, within 120‐ full calendar
days of a RAS operation or a failure of aits RAS to operate
when expected, analyze the RAS performance and
provide the results of the analysis, including any
identified deficiencies, toor on a mutually agreed upon
schedule with its reviewing Reliability Coordinator(s).
The), shall:
5.1 Participate in analyzing the RAS operational
performance analysis shall to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
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Project 2010‐05.3 Remedial Action Schemes (RAS)
PRC‐016‐1 R2:
Covered by Requirements R6
and R7.
R6. Within six full calendar months of being notified of a
deficiency in its RAS pursuant to Requirement R4 or
Requirement R5, each RAS‐ownerR6. Each RAS‐entity
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
shall participate in developing a Corrective Action Plan
(CAP) and submit the CAP to its reviewing Reliability
Coordinator(s).) within six full calendar months of:
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
• Notifying the Reliability Coordinator pursuant to
Requirements R5, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. ForEach RAS‐entity shall, for each CAP submittedof its
CAPs developed pursuant to Requirement R6, each RAS‐
owner shall:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change. and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
PRC‐016‐1 R3:
Distribution Provider that owns a RAS shall provide Covered by Requirements R5,
R6, and R7, Attachment 1.
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
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Project 2010‐05.3 Remedial Action Schemes (RAS)
R5. Each RAS‐owner shallentity, within 120‐ full calendar
days of a RAS operation or a failure of aits RAS to operate
when expected, analyze the RAS performance and
provide the results of the analysis, including any
identified deficiencies, toor on a mutually agreed upon
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Organization and NERC on request (within 90
calendar days).
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
schedule with its reviewing Reliability Coordinator(s).
The), shall:
5.1 Participate in analyzing the RAS operational
performance analysis shall to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
R6. Within six full calendar months of being notified
of a deficiency in its RAS pursuant to Requirement R4
or Requirement R5, each RAS‐owner5.2 Provide the
results of RAS operational performance analysis that
identified any deficiencies to its reviewing Reliability
Coordinator(s).
R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s).) within six full
calendar months of:
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
Mapping Document | AugustNovember 2015
Project 2010‐05.3 Remedial Action Schemes (RAS)
17
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
• Notifying the Reliability Coordinator pursuant to
Requirements R5, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. ForEach RAS‐entity shall, for each CAP submittedof its
CAPs developed pursuant to Requirement R6, each RAS‐
owner shall:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change. and when the
CAP is completed.
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Project 2010‐05.3 Remedial Action Schemes (RAS)
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Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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2
Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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3
NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – 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.
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to provide
the information identified in
Attachment 1 to each Reliability
Coordinator prior to placing a
new or functionally modified
RAS in‐service or retiring an
existing RAS in accordance with
Requirement R1.
6
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30 full calendar days
but less than or equal to 60 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60 full calendar days
but less than or equal to 90 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90 full calendar days.
OR
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
10
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
N/A
14
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, in greater than 60 full
calendar months but less than
or equal to 61 full calendar
months.
Moderate
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, in greater than 61 full
calendar months but less than
or equal to 62 full‐calendar
months
High
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, in greater than 62 full
calendar months but less than
or equal to 63 full calendar
months.
Severe
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but in greater than 63 full
calendar months.
OR
The Planning Coordinator
performed the evaluation in
The Planning Coordinator
accordance with Requirement
performed the evaluation in
R4, but failed to evaluate two or
accordance with Requirement
more of the Parts 4.1.1 through
R4, but failed to evaluate one of 4.1.4.
the Parts 4.1.1 through 4.1.4.
OR
OR
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
receiving entities listed in Part
4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
less than or equal to 10 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 10 full calendar days
but less than or equal to 20 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 20 full calendar days
but less than or equal to 30 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 30 full calendar days.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1.1 through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
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VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10 full calendar days.
Moderate
High
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10 full calendar days but less
than or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20 full calendar days but less
than or equal to 30 full calendar
days.
Severe
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30 full calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐entity failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐entity implemented a
N/A
CAP in accordance with
Requirement R7, Part 7.1, but
failed to update the CAP (Part
7.2) if actions or timetables
changed, or failed to notify (Part
7.3) each of the reviewing
Reliability Coordinator(s) of the
updated CAP or completion of
the CAP.
ifications for PRC‐012‐2, Requirement R7
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High
N/A
Severe
The RAS‐entity failed to
implement a CAP in accordance
with Requirement R7, Part 7.1.
30
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 90 full
calendar days.
OR
The RAS‐entity failed to perform
the functional test for a RAS as
specified in Requirement R8.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30 full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30 full calendar days but less
than or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60 full calendar days but less
than or equal to 90 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than 90
full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
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FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
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Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
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Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – 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.
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to
submitprovide the information
identified in Attachment 1 to
one or more of theeach
Reliability Coordinator(s) prior
to placing a new or functionally
modified RAS in‐service or
retiring an existing RAS in
accordance with Requirement
R1.
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30‐ full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30‐ full calendar days
but less than or equal to 60‐ full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60‐ full calendar days
but less than or equal to 90‐ full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90‐ full calendar
days.
OR
The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in ‐
service or retiring an existing
RAS in accordance with
Requirement R3.
N/A
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with Requirement
R4, in greater than 60‐ full
calendar months but less than
or equal to 61‐ full calendar
months.
Moderate
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with Requirement
R4, in greater than 61‐ full
calendar months but less than
or equal to 62‐ full ‐calendar
months.
High
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with Requirement
R4, in greater than 62‐ full
calendar months but less than
or equal to 63‐ full calendar
months.
OR
Severe
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with Requirement
R4, but in greater than 63‐ full
calendar months.
OR
The Transmission Planner failed
to perform the evaluation in
accordance with Requirement
R4.
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
OR
accordance with Requirement
R4, but failed to evaluate one of The Transmission PlannerThe
Planning Coordinator performed
the Parts 4.1.1 through 4.1.4.
the evaluation in accordance
with Requirement R4, but failed
to evaluate two or more of the
Parts 4.1.1 through 4.1.4.
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
OR
The Transmission
PlannerPlanning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
RAS‐owner(s) and the reviewing
Reliability
Coordinator(s).receiving entities
listed in Part 4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no consequence of lowering the current level of compliance.
FERC VSL G2
Guideline 2a: N/A
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VSL Justifications for PRC‐012‐2, Requirement R4
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 Assignments
that Contain Ambiguous
Language
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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23
VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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24
VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐ownerentity performed
the analysis in greater than 120‐
calendar days, but less than or
equal to 130‐calendar days in
accordance with Requirement
R5, but was late by less than or
equal to 10 full calendar days.
The RAS‐ownerentity performed
the analysis in
greateraccordance with
Requirement R5, but was late by
more than 130‐10 full calendar
days, but less than or equal to
140‐20 full calendar days in
accordance with Requirement
R5.
The RAS‐ownerentity performed
the analysis in
greateraccordance with
Requirement R5, but was late by
more than 140‐20 full calendar
days, but less than or equal to
150‐30 full calendar days in
accordance with Requirement
R5.
The RAS‐ownerentity performed
the analysis in
greateraccordance with
Requirement R5, but was late by
more than 150‐30 full calendar
days.
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OR
The RAS‐owner failed to
perform the analysis in
OR
accordance with Requirement
The RAS‐ownerentity performed R5.
the analysis in accordance with
OR
Requirement R5, but failed to
The RAS‐ownerThe RAS‐entity
address one of the Parts 5.1.1
performed the analysis in
through 5.1.4.
accordance with Requirement
R5, but failed to address two or
more of the Parts 5.1.1 through
5.1.4.
25
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐ownerentity performed
the analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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26
VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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27
VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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28
VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐ownerentity developed
a Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10‐ full calendar days.
The RAS‐ownerentity developed
a Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10‐ full calendar days but less
than or equal to 20‐ full calendar
days.
The RAS‐ownerentity developed
a Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20‐ full calendar days but less
than or equal to 30‐ full calendar
days.
The RAS‐ownerentity developed
a Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30‐ full calendar days.
OR
The RAS‐ownerentity developed
a Corrective Action Plan andbut
failed to submit it to one or
more of its reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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29
VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐ownerentity failed to
develop a Corrective Action Plan
in accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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30
VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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31
VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐ownerentity
N/A
implemented a CAP (in
accordance with Requirement
R7, Part 7.1),, but failed to
update the CAP (Part 7.2) if
actions or timetables changed
and, or failed to notify one or
more(Part 7.3) each of the
reviewing Reliability
Coordinator(s) (Part 7.3), in
accordance with Requirement
R7of the updated CAP or
completion of the CAP.
ifications for PRC‐012‐2, Requirement R7
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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High
N/A
Severe
The RAS‐ownerentity failed to
implement a CAP (Part 7.1) in
accordance with Requirement
R7, Part 7.1.
33
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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35
VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐ownerentity performed
the functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30‐ full calendar days late.
The RAS‐ownerentity performed
the functional test for a RAS as
specified in Requirement R8, but
was late by more than 30‐ full
calendar days but less than or
equal to 60‐ full calendar days
late.
The RAS‐ownerentity performed
the functional test for a RAS as
specified in Requirement R8, but
was late by more than 60‐ full
calendar days but less than or
equal to 90‐ full calendar days
late.
The RAS‐ownerentity performed
the functional test for a RAS as
specified in Requirement R8, but
was late by more than 90‐ full
calendar days late.
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OR
The RAS‐ownerentity failed to
perform the functional test for a
RAS as specified in Requirement
R8.
37
VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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38
VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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39
VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30‐ full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30‐ full calendar days but less
than or equal to 60‐ full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60‐ full calendar days but less
than or equal to 90‐ full calendar
days.
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than
90‐ full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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41
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document | AugustNovember 2015
42
Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
November 2015
Table of Contents
Question & Answer for PRC‐012‐2 ............................................................................................................................ 2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ........................... 2
2. Why is the 60 month evaluation of Requirement R4 assigned to the Planning Coordinator? .......................... 2
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ......... 3
4. Why do RAS need to be reviewed and approved by a group other than the RAS‐entity? ................................ 3
5. What is required for RAS “single component failure” and why? ....................................................................... 3
6. What is required for RAS “inadvertent operation” and why? ........................................................................... 4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ............................................................................................................................................................. 5
8. Why are RAS classifications not recognized in the standard? ........................................................................... 5
9. What constitutes a functional modification of a RAS? ...................................................................................... 6
Attachment A – Project Roster…………………………………………………………………………………………………………………………….7
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
Question & Answer | November 2015
1
Question & Answer for PRC-012-2
The Project 2010‐05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC‐012‐2.
1.
Why is the Remedial Action Scheme (RAS) review assigned to the
Reliability Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk‐Power System. The NERC white paper suggested
Reliability Coordinators (RCs) and Planning Coordinators (PCs) for RAS‐review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best‐suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest‐area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. The Wide Area purview better facilitates
the evaluation of interactions among separate RAS, as well as interactions among RAS and other
protection and control systems. The selection of the RC also minimizes the possibility of a conflict
of interest that could exist because of business relationships among the RAS‐entity, Planning
Coordinator, Transmission Planner, or other entities involved in the planning or implementation
of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain
objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2.
Why is the 60 month evaluation of Requirement R4 assigned to the
Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least every 60 calendar
months to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November 2015
2
3.
Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP‐1‐3 Requirement R13 requires Balancing Authorities (BA) and Transmission Owners (TO) to
perform operational reliability assessments (e.g., real time contingency analysis (RTCA), day‐
ahead, seasonal) that include data describing new or degraded RAS. In addition, IRO‐005‐4
requires RCs to share any pertinent data, such as data from RAS, with potentially affected BAs
and TOs. Operating horizon assessments that include RAS are already required by other
standards, so an additional requirement duplicating that effort is not necessary.
TPL‐001‐4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near‐term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short‐term (annual) planning horizon assessments are already
required by the TPL‐001‐4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS‐entities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why?
The existing PRC‐012‐1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.4 and
Attachment 1 of PRC‐012‐2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November 2015
3
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
Using alternative automatic actions to back up failures of single RAS components.
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re‐dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review process and designated as Type 3
in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When
appropriate, new or functionally modified RAS implemented after the effective date of this
standard will be designated as limited impact by the Reliability Coordinator during the RAS review
process. Limited impact schemes are not subject to the single component failure aspect of
Requirement R4, Part 4.1.4.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC‐012‐1 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0) as that required of the contingency for which
it was designed and not exceed TPL‐003‐0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.3 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL‐001‐4 or for System conditions
not defined in TPL‐001‐4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.3.1 – 4.1.3.5, which are the
performance requirements common to all planning events P0–P7.
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November 2015
4
date of this standard that has been through the regional review process and designated as Type 3
in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When
appropriate, new or functionally modified RAS implemented after the effective date of this
standard will be designated as limited impact by the Reliability Coordinator in conjunction with
the RAS review process. Limited impact schemes are not subject to the single component
malfunction aspect of Requirement R4, Part 4.1.3.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific System configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post‐Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS‐SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC‐012‐1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.4 and Attachment 1, item III.4
of PRC‐012‐2 that relates to single component failure; consequently, there is no need to have a
formal classification for this purpose.
Similarly, the standard drafting team concluded that the SPCS‐SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC‐
012‐1, and problematic due to the difficulty of drawing a universally satisfactory delineation in
generally worded classification criteria. Within the RAS review process of PRC‐012‐2, there is a
provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation,
angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be
recognized as limited impact. When appropriate, new or functionally modified RAS implemented
after the effective date of this standard will be designated as limited impact by the Reliability
Coordinator in conjunction with the RAS review process.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November 2015
5
9.
What constitutes a functional modification of a RAS?
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in‐kind replacement of existing components
• Changes to RAS logic beyond error correcting
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS‐entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor that carries RAS communication when such changes may be
important to the timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component, or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation logic.
The Supplementary Material section of Reliability Standard PRC‐012‐2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November 2015
6
Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles‐Eric Langlois
Hydro‐Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November 2015
7
Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
AugustNovember 2015
Table of Contents
1. Why was the Reliability Coordinator chosen to perform the Remedial Action Scheme (RAS) review?
............................................................................................................................................................................ 2
2. Why is the Planning Coordinator not required to perform an annual evaluation of RAS
performance? ..................................................................................................................................... 32
3. Why is the five‐year evaluation assigned to the Transmission Planner rather than the Reliability
Coordinator? ........................................................................................................................................ 3
4. Why do RAS need to be reviewed and approved by a group other than the RAS‐owner? ................. 3
5. What is required for RAS “single component failure” and why is it required? ................................. 43
6. What is required for RAS inadvertent operation? ............................................................................. 54
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and
control systems? ................................................................................................................................ 65
8. Why are RAS classifications not recognized in the standard? ........................................................... 65
9. What constitutes functional modification of a RAS? ......................................................................... 85
10. Why is the RAS‐entity identified in the standard and what are its responsibilities? ........................ 86
Attachment A – Project Roster ......................................................................................................................... 107
Question & Answer for PRC‐012‐2 ............................................................................................................................ 2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ........................... 2
2. Why is the 60 month evaluation of Requirement R4 assigned to the Planning Coordinator? .......................... 3
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ......... 3
4. Why do RAS need to be reviewed and approved by a group other than the RAS‐entity? ................................ 3
5. What is required for RAS “single component failure” and why? ....................................................................... 4
6. What is required for RAS “inadvertent operation” and why? ........................................................................... 5
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ............................................................................................................................................................. 6
8. Why are RAS classifications not recognized in the standard? ........................................................................... 6
9. What constitutes a functional modification of a RAS? ...................................................................................... 8
Attachment
A
–
Roster…………………………………………………………………………………………………………………………….10
Project 2010‐05.3 Phase 3 of Protection Systems:‐: Remedial Action Schemes
Question & Answer | AugustNovember 2015
Project
1
Question & Answer for PRC-012-2
The Project 2010‐05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC‐012‐2.
1.
Why was the Reliability Coordinator chosen to performis the
Remedial Action Scheme (RAS) review? assigned to the Reliability
Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk‐Power System. The NERC white paper suggested
Planning Coordinators (PCs) and Reliability Coordinators (RCs) and Planning Coordinators (PCs)
for RAS‐review responsibility. The SDT considered the suggestion and ultimately chose the
Reliability Coordinator because of the RC has the widest possible view of the System of any
operating or planning entity. Some Regions have as many as 30 PCs for one RC while other
Regions or other System footprints have a single PC and RC for the same area. Overall, there are
16 RCs and approximately 80 PCs in North America. The large RC geographic oversight will
minimize fragmentation of the regional reviews currently administered by the Regions and
promote continuity.
The RC is the best‐suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest‐area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. This wide‐area purview provides
continuity in the review process andThe Wide Area purview better facilitates the evaluation of
interactions among separate RAS, as well as interactions among RAS and other protection and
control systems. The selection of the RC also minimizes the possibility of a conflict of interest that
could exist because of business relationships among the RAS‐entity, PCPlanning Coordinator,
Transmission Planner (TP),, or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can
therefore maintain objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
2
2.
Why is the 60 month evaluation of Requirement R4 assigned to the
Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least every 60 calendar months
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be addressed in
the evaluations include: 1) RAS mitigation of the System condition(s) or event(s) for which it was
designed; 2) RAS avoidance of adverse interactions with other RAS and with protection and control
systems; 3) the impact of inadvertent operation; and 4) the impact of a single component failure. The
evaluation of these items involves modeling and studying the interconnected transmission system,
similar to the planning analyses performed by PCs.
2.3. Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP‐005‐1‐3 Requirement R3R13 requires Balancing Authorities (BA) and Transmission Owners
(TO) to perform operational reliability assessments (e.g., real time contingency analysis (RTCA),
day‐ahead, seasonal) that include data describing new or degraded RAS. In addition, IRO‐005‐1
Requirement R124 requires RCs to share any pertinent data, such as data from RAS, with
potentially affected BAs and TOs. Operating horizon assessments that include RAS are already
required by other standards, so an additional requirement duplicating that effort is not
necessary.
TPL‐001‐4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near‐term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short‐term (annual) planning horizon assessments are already
required by the TPL‐001‐4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
3. Why is the five-year evaluation assigned to the Transmission
Planner rather than the Reliability Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least every 60 calendar
months to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, which is very similar to the planning analyses performed by
the TPs. The RC is more focused on actual System conditions, not necessarily on the conditions
for which a RAS was designed. The required evaluation is a detailed planning analysis and thus
the TP is better suited than the RC to perform the evaluation.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
3
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-owner? entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS‐ownersentities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why is it
required? ?
The existing PRC‐012‐1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.4 and
Attachment 1 of PRC‐012‐2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
Using alternative automatic actions to back up failures of single RAS components.
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re‐dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
4
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review process and designated as Type 3
in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When
appropriate, new or functionally modified RAS implemented after the effective date of this
standard will be designated as limited impact by the Reliability Coordinator during the RAS review
process. Limited impact schemes are not subject to the single component failure aspect of
Requirement R4, Part 4.1.4.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC‐012‐01 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0) as that required of the contingency for which
it was designed and not exceed TPL‐003‐0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.3 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL‐001‐4 or for System conditions
not defined in TPL‐001‐4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.3.1 – 4.1.3.5, which are the
performance requirements common to all planning events P0–P7.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
5
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review process and designated as Type 3
in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When
appropriate, new or functionally modified RAS implemented after the effective date of this
standard will be designated as limited impact by the Reliability Coordinator in conjunction with
the RAS review process. Limited impact schemes are not subject to the single component
malfunction aspect of Requirement R4, Part 4.1.3.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific systemSystem configurations to determine
whether they need to arm or take action. Though unusual, overlapping actions among RAS would
have the potential to result in Cascading unless they were coordinated. Similarly, RAS operation
can change System configuration and available fault duty, which can affect coordination with
distance relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A
third coordination example is RAS operational timing that must coordinate with automatic
reclosing on a faulted line. Many RAS are intended to mitigate post‐Contingency overloads. A
short coordinating delay up to a few seconds is required to avoid initiating action until a System
Fault can be detected and cleared by Protection System action. A delay of several minutes may
be acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS‐SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC‐012‐1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.4 and Attachment 1, item III.4
of PRC‐012‐2 that relates to single component failure; consequently, there is no need to have a
formal classification for this purpose.
TheSimilarly, the standard drafting team concluded that the SPCS‐SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC‐
012‐1 R1.3 which does not recognize such a distinction, and problematic due to the difficulty of
drawing a universally satisfactory delineation in generally worded classification criteria. Within
the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as “limited
impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse,
or unacceptably damped oscillations. A RAS implemented prior to the effective date of this
standard that has been through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate, new
or functionally modified RAS implemented after the effective date of this standard will be
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
6
designated as limited impact by the Reliability Coordinator in conjunction with the RAS review
process.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
7
9.
What constitutes a functional modification of a RAS?
Any change in RAS logic, relay settings, control settings, or any other modification that affects
overall RAS functionality, timing, or redundancy level are changes to functionality documented in
the original submission for review. RAS modifications identified by a CAP developed pursuant to
Requirement R6—beyond the substitution of components that preserve the original
functionality—are functional changes.
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in‐kind replacement of existing components
• Changes to RAS logic beyond error correcting
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS‐entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in the physical design,
settings, or device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor within athat carries RAS component station.
Suchcommunication when such changes could affectmay be important to the throughput
timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component., or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation settings or custom logic.
10. Why is the RAS-entity identified in the standard and what are its
responsibilities?
The purpose of the RAS‐entity is to be the single information conduit with the reviewing RC for all
RAS‐owners for each RAS. The RAS‐entity needs to coordinate all review materials and any
presentations. If all RAS equipment has a single owner, then the RAS‐entity is the RAS‐owner, and
that owner speaks for itself.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
8
A RAS can have more than one owner. The RAS‐entity is always one of the RAS‐owners and is
designated by all RAS‐owners. Historically, the owner of the RAS controller (most commonly a
Transmission Owner) is the RAS‐entity.
RAS‐owners who are not the RAS‐entity still have responsibilities as assigned in other NERC
standards, such as equipment maintenance in PRC‐005. In addition, when RAS modifications are
needed; e.g., per Requirement R6 or Attachment 1, each RAS‐owner must participate in
developing a CAP and accept the specific responsibilities assigned to them in the CAP or
otherwise as described in the revised Attachment 1.
The Supplementary Material section of Reliability Standard PRC‐012‐2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
9
Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles‐Eric Langlois
Hydro‐Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | AugustNovember 2015
10
Standards Announcement Reminder
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2 and Proposed Definition of “Special Protection
System”
Additional Ballot, Non-binding Poll, and Initial Ballot Open through January 8, 2016
Now Available
An additional ballot for PRC-012-2 – Remedial Action Schemes, a non-binding poll of the associated
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) and an initial ballot for the Proposed
Definition of “Special Protection System” are open through 8 p.m. Eastern, Friday, January 8, 2016.
The standard drafting team’s considerations of the responses received from the last comment period are
reflected in this draft of the standard.
Balloting
Members of the ballot pools associated with this project may log in and submit their votes for the
standard, associated VRFs and VSLs, and definition by clicking here.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2 and Proposed Definition of “Special Protection
System”
Formal Comment Period Open through January 8, 2016
Now Available
A 45-day formal comment period for PRC-012-2 – Remedial Action Schemes and the Proposed
Definition of “Special Protection System” is open through 8 p.m. Eastern, Friday, January 8, 2016.
The standard drafting team’s considerations of the responses received from the last comment period are
reflected in this draft of the standard.
Commenting
Use the electronic form to submit comments on the standard and proposed definition. If you experience
any difficulties in using the electronic form, contact Wendy Muller. An unofficial Word version of the
comment form is posted on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
An additional ballot for the standard and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels as well as an initial ballot for the proposed definition will be conducted
December 30, 2015 through January 8, 2016.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2 and Proposed Definition of “Special Protection
System”
Formal Comment Period Open through January 8, 2016
Now Available
A 45-day formal comment period for PRC-012-2 – Remedial Action Schemes and the Proposed
Definition of “Special Protection System” is open through 8 p.m. Eastern, Friday, January 8, 2016.
The standard drafting team’s considerations of the responses received from the last comment period are
reflected in this draft of the standard.
Commenting
Use the electronic form to submit comments on the standard and proposed definition. If you experience
any difficulties in using the electronic form, contact Wendy Muller. An unofficial Word version of the
comment form is posted on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
An additional ballot for the standard and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels as well as an initial ballot for the proposed definition will be conducted
December 30, 2015 through January 8, 2016.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
PRC-012-2 and Proposed Definition of “Special Protection
System”
Ballot and Non-binding Poll Results
Now Available
A formal comment period and additional ballot for PRC-012-2 – Remedial Action Schemes, as well as a
non-binding poll of the associated Violation Risk Factors and Violation Severity Levels and an initial ballot
for the Proposed Definition of “Special Protection System” concluded 8 p.m. Eastern, Friday, January 8,
2016.
The voting statistics are listed below, and the Ballot Results page provides detailed results for the ballots
and non-binding poll.
PRC-012-2
Definition of “Special
Protection System”
Non-binding Poll
Quorum / Approval
Quorum / Approval
Quorum / Supportive
Opinions
83.39% / 60.39%
80.88% / 92.94%
81.21% / 58.39%
Next Steps
The drafting team will consider all comments received during the formal comment and determine the
next steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at (404) 4469675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Survey Report
Survey Details
Name
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS) | PRC012-2 and Definition
Description
Start Date
11/25/2015
End Date
1/8/2016
Associated Ballots
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes Definition IN 1 DEF
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 AB 2 ST
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 Non-binding Poll AB
2 NB
Survey Questions
1.
Limited impact designation: Within the RAS review process of PRC-012-2, the drafting team
included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. A RAS implemented prior to the effective date of this standard that has been
through the regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or
LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited
impact by the Reliability Coordinator during the RAS review process. Do you agree with the
provision that RAS can be designated as “limited impact”? If no, please provide the basis for
your disagreement and an alternate proposal.
Yes
No
2.
Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to
provide clarity and to lengthen the implementation period to thirty-six months to provide the
responsible entities adequate time to establish the new working frameworks among functional
entities. Do you agree with the revised Implementation Plan? If no, please provide the basis for
your disagreement and an alternate proposal.
Yes
No
3. Revised Definition of SPS and its Implementation Plan: The drafting team revised the
definition of Special Protection System to cross-reference the revised definition of Remedial
Action Scheme. The Implementation Plan for the revised definition of Special Protection System
aligns with the effective date of the revised definition of Remedial Action Scheme. Do you agree
with the proposed definition and its implementation plan? If no, please provide the basis for your
disagreement and an alternate proposal.
Yes
No
4.
If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
Responses By Question
1.
Limited impact designation: Within the RAS review process of PRC-012-2, the drafting team
included a provision that RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. A RAS implemented prior to the effective date of this standard that has been
through the regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or
LAPS in WECC will be recognized as limited impact. When appropriate, new or functionally
modified RAS implemented after the effective date of this standard will be designated as limited
impact by the Reliability Coordinator during the RAS review process. Do you agree with the
provision that RAS can be designated as “limited impact”? If no, please provide the basis for
your disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Falsey - Invenergy LLC - 3 - FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5 - RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
The references to “limited impact” pose significant potential for confusion and
impact reliability through ambiguity as currently documented. As written, the term
“limited impact” is documented an unofficial definition within a single standard.
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Although we agree there is a concern that the availability of the "limited impact"
definition may lead to overuse of this option.
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
Yes
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
Yes
Answer Comment:
We appreciate the SDT's responsiveness to our comment in the previous posting
advocating the provision of "limited impact" RAS.
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Tri-State supports the introduction of the concept of "limited impact".
Document Name:
Likes:
0
Dislikes:
0
Laura Nelson - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Yes
Answer Comment:
PSEG supports the concept of a limited impact RAS designation within PRC-0122 provided that it is defined and made available to all RAS entities.
PSEG wishes to note that the criteria for the limited impact designation proposed
in draft# 2 of PRC-012-2 are not consistent with the term as it was defined in the
NERC SPCS report “Special Protection Systems (SPS) and Remedial Action
Schemes (RAS): Assessment of Definition, Regional Practices, and Application of
Related Standards” dated April, 2013. Under that report, a SPS/RAS has a
limited impact to the BES if failure or inadvertent operation of the scheme does
not result in any of the following:
• Non-Consequential Load Loss ≥ 300 MW;
• Aggregate resource loss (tripping or runback of generation or HVdc) > the
largest Real Power resource within the interconnection;
• Loss of synchronism between two or more portions of the system each
including more than one generating plant; or
• Negatively damped oscillations.
If none of the four results are projected to occur, the SPS is classified as having a
limited impact on the BES.
While PSEG agrees with the existing NPCC, ERCOT, and WECC limited impact
designations, PSEG also believes that one NERC-wide limited impact RAS
criteria should be included in PRC-012-2 for new limited impact designations.
While PSEG does not advocate any specific limited impact RAS criteria, it does
note that the cited SPCS report was approved by the NERC Planning Committee.
Any RAS that meets such criteria, whether existing or proposed, should receive
limited impact designation.
Finally, second draft of PRC-012-2 does not provide an affirmative mechanism for
an existing RAS to be classified as limited impact. In order for such a review take
place under R2, a RAS-entity must initiate the review (under R1) when: “…placing
a new or functionally modified RAS in-service or retiring and existing
RAS”. Therefore, under our reading of the current draft of PRC-012-2, existing
RASs which are not undergoing functional modification do not have an
opportunity to be reviewed for a limited impact designation, and R1 should be
modified to allow such RAS entities to seek designation for existing RASs as
“limited impact.” To facilitate such analysis, PSEG’s comments in Q4 request that
the RAS entity’s Planning Coordinator have obligations under R1 to perform the
studies related to a RAS’s performance that is required in Attachment 1.
Document Name:
Likes:
5
Dislikes:
0
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Daniel Mason - City and County of San Francisco - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
William Temple - William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Selected Answer:
Yes
Answer Comment:
The Standards Drafting Team (SDT) states a RAS which is “…new or functionally
modified RAS implemented after the effective date…” can be recognized as
“limited impact.” Can a RAS currently in place and not within the Types already
“grandfathered” by this standard (e.g., Type 3 in NPCC, Type 2 in ERCOT),
become recognized as “limited impact?” We request the SDT provide more
clarity on the process for determining “limited impact” on existing RASs.
Document Name:
Likes:
0
Dislikes:
0
Greg Davis - Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1 Selected Answer:
Yes
Answer Comment:
Tacoma Power appreciates this provision.
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Yes
Answer Comment:
The SDT states a RAS which is “…new or functionally modified RAS
implemented after the effective date…” can be recognized as “limited impact”.
Can a RAS currently in place and not within the Types already “grandfathered” by
this standard, become recognized as “limited impact”? If so, what is the
process?
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
No
Answer Comment:
Please see response to Question #4.
Document Name:
Likes:
0
Dislikes:
0
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Steve Wenke - Avista - Avista Corporation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Gowder - Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC
Group Information
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name Entity
Region
Segments
Paul Malozewski
Hydro One.
NPCC
1
Guy Zito
Northeast Power Coordinating
Council
NPCC
NA - Not
Applicable
Brian Shanahan
National Grid
NPCC
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY-ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability
Council
NPCC
7
Kathleen M. Goodman
ISO-New England
NPCC
2
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Michael Jones
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Voter Information
Voter
Segment
Ruida Shu
1,2,3,4,5,6,7
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rich Hydzik - Rich Hydzik On Behalf of: Bryan Cox, Avista - Avista Corporation, 5, 3, 1
Scott Kinney, Avista - Avista Corporation, 5, 3, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
No
Answer Comment:
Texas RE does not agree with the provision that a RAS can be designated as
“limited impact”. Moreover, Texas RE recommends the STD reconsider and treat
all RASes equally, that affect the reliability of the Bulk Electric System
(BES). Texas RE is concerned the proposed criteria for determining a “limited
impact” RAS is vague and ambiguous (e.g. “… BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations) which may lead to the approval of a significant
number of “limited impact” RASes on the BES, posing a potential risk to
reliability. Specifically, the potential risks are that the reduced reliability-related
considerations for the Reliability Coordinator (i.e. Attachment 2) and the limited
evaluation performed by the Planning Coordinator (i.e. Requirement 4) pertaining
to “limited impact” RASes may lead to potential reliability gaps on the BES.
In the ERCOT region, the “Type 1” and “Type 2” designations were removed from
the regional operating guides in February 2014, therefore, there is no longer a
regional criteria for “limited” or “wide-area” impact as referred to in R4.1.3. As
one of the goals of this project was to eliminate the “fill-in-the-blank”
requirements, it seems inappropriate to refer to regional criteria within the
standard as it does in footnotes 1, 3, 5, and 6. Texas RE requests the SDT
remove that information from the footnotes.
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Florida Power & Light appreciates the efforts of the Standard Drafting Team in
revising PRC-012-2, however we have concerns on the interpretation of “limited
impact” as stated in PRC-012-2 standard. In many cases, RAS’s that are
classified as “limited impact” may have a larger than expected impact due to
system changes. As an example, see page 8 of the NPCC Reliability Reference
Directory #7 – Special Protection Systems. NPCC states that “it should be
recognized that a Type III SPS may, due to system changes become Type 1 or
Type II”.
To ensure uniform application, we recommend the footnote in Requirement 4 be
modified as follows:
“…RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading,
uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations for the system conditions considered in the
latest TPL-001-4 stability assessment.”
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Wilson - Independent Electricity System Operator - 2 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Oshani Pathirane - Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1,
3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
No
Answer Comment:
While Hydro One supports the newly introduced designation of "limited impact"
RAS, we feel that its definition should instead read as shown below, in order to
ensure that future in-serviced RAS that will be designated by a regional review
process as Type 3 (NPCC), Type 2 (ERCOT), or LAPS (WECC) will continue to
be designated as having limited impact. This is because at this early stage, it is
unclear whether the regional organizations would be modifying or terminating
their RAS review process and/or terminology as this process will newly be
conducted by the PC. For example, after the standard is approved, new Type 3
RASs added to the NPCC system would not necessarily be designated as being
limited impact. This change in verbiage will also minimize the need for RASentities to classify RAS into the three categories below:
1) Limited impact as per NERC;
2) Non-limited impact as per NERC;
3) NPCC Type 3 but non-limited impact as per NERC.
"A RAS that was reviewed previously to the effective date of this standard,
or after the effective date of this standard, by a regional process and
designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be
recognized as limited impact for the purposes of Requirement 4, Parts 4.1.3
and 4.1.3."
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
No
Answer Comment:
Limited impact RAS appears to be exempt from R4.1.3 and R4.1.4. The
Rationale box for R4 defines the performance required for a “limited impact” RAS,
and then R4.1.3 and R1.4.4 define the performance required for RAS except
“limited impact” RAS. BPA believes the performance for all RAS should be the
same. Limited impact RAS should not be singled out to be exempt from meeting
the performance requirements; it is really a matter of whether or not redundancy
is required to be able to meet the required performance.
Although BPA agrees that for a “limited impact” RAS the level of review can be
lower, we believe a “limited impact” RAS should still be designed such that failure
or inadvertent operation of the RAS does not have an adverse impact on an
adjacent TP or PC beyond the criteria the system is planned for.
BPA’s comments also apply to Attachment 2.
Document Name:
Likes:
0
Dislikes:
0
Ben Engelby - ACES Power Marketing - 6 Group Information
Group Name:
ACES Standards Collaborators - PRC-012-2 Project
Group Member Name Entity
Region
Segments
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Mark Ringhausen
Old Dominion Electric
Cooperative
RFC
3,4
Ryan Strom
Buckeye Power, Inc.
RFC
4
Matt Caves
Western Farmers Electric
Cooperative
SPP
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
WECC
1,4,5
Kevin Lyons
Central Iowa Power Cooperative
MRO
1
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Voter Information
Voter
Segment
Ben Engelby
6
Entity
Region(s)
ACES Power Marketing
Selected Answer:
No
Answer Comment:
(1) The SDT needs to provide more details for “limited impact.” This is a vague
term that needs to be clarified, as “cause or contribute to BES Cascading” could
be interpreted in multiple ways. Any system that fails to operate as designed
could be a contributing cause to an outage. How does an entity prove that a RAS
does not cause cascading? It may be impossible to prove that a RAS has limited
impact.
(2) Why does the SDT give the RC the independent authority without any
specific criteria or guidelines to determine if the RAS has a limited impact? There
should be an objective set of criteria for the RC to make a decision. We suggest
adding detailed parameters or specific examples to show how a RAS may have a
limited impact. One suggestion is a local area scheme that does not impact a
larger area. The SDT could also leverage SPP, WECC or NPCC parameters for
determining limited impact that should lead to the SDT to develop continent-wide
criteria for determining limited impact RAS.
(3) Why does the SDT include “limited impact” RAS as being applicable to the
standard? If it has a limited impact, then it should not apply at all. This proposal
by the SDT is contrary to the past two years of NERC’s RAI and RBR initiatives
focusing on HIGH RISK activities. By definition, “limited impact” should not
matter for BES reliability. The limited impact designation creates unnecessary
compliance burdens without a clear benefit to increased reliability of the grid.
Document Name:
Likes:
0
Dislikes:
0
Phil Hart - Associated Electric Cooperative, Inc. - 1 Group Information
Group Name:
AECI
Group Member Name Entity
Region
Segments
Mark Ramsey
N.W. Electric Power Cooperative, SERC
Inc.
1
John Stickley
N.W. Electric Power Cooperative, SERC
Inc.
3
Kevin White
Northeast Missouri Electric Power SERC
Cooperative
1
Skyler Wiegmann
Northeast Missouri Electric Power SERC
Cooperative
3
Michael B Bax
Central Electric Power
Cooperative
SERC
1
Adam M Weber
Central Electric Power
Cooperative
SERC
3
Denise Stevens
Sho-Me Power Electric
Cooperative
SERC
1
Jeff L Neas
Sho-Me Power Electric
Cooperative
SERC
3
Walter Kenyon
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
SERC
1
Todd Bennett
Associated Electric Cooperative
Inc.
SERC
3
Matt Pacobit
Associated Electric Cooperative
Inc.
SERC
5
Brian Ackermann
Associated Electric Cooperative
Inc.
SERC
6
Voter Information
Voter
Segment
Phil Hart
1
Entity
Region(s)
Associated Electric Cooperative, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Yes
Answer Comment:
ERCOT supports the comments submitted by the IRC SRC and provides these
additional comments.
ERCOT agrees with the SDT that a “limited impact” designation should be
available. However, ERCOT no longer uses the RAS designations “Type 1” or
“Type 2,” and references to “ERCOT Type 2” in the footnotes and rationale boxes
of this draft standard should be removed. The now defunct ERCOT “Type 2”
designation was used to identify limited impact RAS.
Today, there are existing RAS in ERCOT that, although they are no longer
designated “Type 2” still qualify as “limited impact.” ERCOT requests clarification
as to any particular process that would be required to designate an existing RAS
as “limited impact.”
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Yes
Answer Comment:
There are 4 WECC LAPS that exist which could, given failure to operate,
contribute to cascading or voltage instability/collapse. Peak will work with WECC
during the implementation phase to update these designations.
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
MRO,SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
2.
Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to
provide clarity and to lengthen the implementation period to thirty-six months to provide the
responsible entities adequate time to establish the new working frameworks among functional
entities. Do you agree with the revised Implementation Plan? If no, please provide the basis for
your disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Falsey - Invenergy LLC - 3 - FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
No
Answer Comment:
As written, the implementation plan creates confusion by singling out the 3
exceptions. SRP recommends identifying the requirements applicable with the 36
month timeframe. Additionally, as written, there is not established effective date
for R9 where a database does not exist.
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
Yes
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
No
Answer Comment:
While Xcel Energy agrees with the clarifications in the Implementation Plan, we
do not believe that BES reliability is well served by substantially increasing the
revised standard’s effective date from 12 to 36 months. Recognizing that 12-18
months is typically the minimum time taken by a NERC Standard to progress from
industry approval to receiving FERC approval, a 36 months adder would
effectively push the standard’s effective date to 4 -5 years after industry approval
– which we believe is an inordinately long and unnecessary delay to realize the
BES reliability benefits promised by the proposed results-based standard. It is
hard to conceive why the responsible entities would need 4-5 years “to establish
the new working frameworks among functional entities” given that the only
substantial process change in the proposed standard is due to the Reliability
Coordinator serving as the RAS review/approval entity – and the associated new
working framework is needed to support only R2 (and perhaps R3 to some
extent), which constitutes a small proportion of the standard.
Therefore, from our perspective, majority of the requirements are the functional
responsibility of a single applicable entity and do not require establishing “new
working frameworks among functional entities”. Consequently, the previous 12
months implementation period is reasonably adequate – particularly because all
existing RAS would retain status quo for several years beyond the standard’s
effective date due to the: (a) provision of limited impact RAS, and (b)
grandfathering of all existing approved RAS until a functional modification
occurs. We recommend reducing the implementation period back to 12 months
to realize enhanced BES reliability in a more timely manner with the new resultsbased standard.
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Laura Nelson - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Yes
Answer Comment:
PSEG strongly supports the 36-month implementation period as fair and
reasonable.
Document Name:
Likes:
5
Dislikes:
0
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Daniel Mason - City and County of San Francisco - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
William Temple - William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Selected Answer:
No
Answer Comment:
The SDT should accommodate the designation of “limited impact” RAS during the
implementation period of PRC-012-2. As stated in our comments to Question 1
above, there needs to be a process in place to allow the RC and RAS entity to do
this.
Document Name:
Likes:
0
Dislikes:
0
Greg Davis - Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
No
Answer Comment:
The SDT should accommodate the designation of “limited impact” RAS during the
implementation period of PRC-012-2. As stated above, there needs to be a
process in place to allow the RC and RAS entity to do this.
There should be an explicit statement in the implementation plan that the
obligation for RC approvals apply only to those new and modified RAS after the
effective date of the standard, not to those that had been previously reviewed by
the RROs under the existing standard.
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Steve Wenke - Avista - Avista Corporation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Gowder - Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
FMPA believes 36 months is too long, and would suggest a timeframe between
12 and 36 months.
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC
Group Information
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name Entity
Region
Segments
Paul Malozewski
Hydro One.
NPCC
1
Guy Zito
Northeast Power Coordinating
Council
NPCC
NA - Not
Applicable
Brian Shanahan
National Grid
NPCC
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY-ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability
Council
NPCC
7
Kathleen M. Goodman
ISO-New England
NPCC
2
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Michael Jones
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Voter Information
Voter
Segment
Ruida Shu
1,2,3,4,5,6,7
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Yes
Answer Comment:
Revise in R8 “Requirement R8 must be completed at least once within six (6) full
calendar years of the effective date for PRC
‐0
be completed at least once within six (6) full calendar years AFTER the effective
“prior to
2”.
date for PRC
‐012‐
the effective date” whereas “after” is clearly stating there is no requirement to
present evidence prior to the effective date. If the SDT agrees then R4 should be
modified as well.
Revise R9 to:
For each Reliability Coordinator that does not have a RAS database upon the
effective date of PRC
‐012
Requirement R9 is to establish a database on the effective date of PRC-012-2 as
describe above. Each RC will perform the obligation of R9 within twelve full
calendar months after the effective date of PRC-012-2 as describe above.
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rich Hydzik - Rich Hydzik On Behalf of: Bryan Cox, Avista - Avista Corporation, 5, 3, 1
Scott Kinney, Avista - Avista Corporation, 5, 3, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
No
Answer Comment:
Texas RE recommends reducing the implementation period. This is a series of
processes that already exist in some form or fashion and should not require a
new construct that would take three years. In Requirement R9, the SDT indicates
requirements follow “industry practice” which is a twelve month periodicity. Does
the SDT contend that there are RASes in place that an RC or PC does not know
about?
Texas RE recommends that the SDT eliminate the proposed implementation
period or at least shorten the proposed three-year implementation period for
PRC-12-2 to six months. Alternatively, the SDT should link the 60-full-calendar
month compliance window in PRC-12-2, R4 and the six- and twelve-year
compliance periods in PRC-12-2, R8 to the effective date of PRC-12-2 and not
the extended date (if any) set forth in the proposed implementation plan.
The proposed PRC-12-2 establishes a process for reviewing new, functionally
modified, or retiring RAS. As the SDT has recognized, failing to implement such
a RAS review process could result in a significant gap in reliability. Specifically,
the SDT stated in the rationale for Requirement R1 that RAS “action(s) can have
a significant impact on the reliability and integrity of the Bulk Electric System
(BES).” Given the importance of the RAS review scheme for reliability, Texas RE
believes that three years is too long to implement the process contemplated in the
proposed PRC-12-2.
Texas RE also believes that the nature of the review process itself also counsels
in favor of a shorter review period. For example, PRC-12-2, R1 – R3 establishes
the basic framework for RAS review. These requirements mandate that RASentities provide certain information regarding RAS to their respective Reliability
Coordinators (RC), a minimum four-month period for the RC to review this
information, and then a subsequent obligation for the RAS-entity to resolve any
reliability issues identified by the RC prior to installing, functionally modifying, or
retiring a particular RAS. Accordingly, these requirements do not contemplate
immediate changes to existing physical assets, significant internal process
transformations, or other issues that could potentially justify a three-year
implementation period. Rather, they largely focus solely on the exchange and
review of documentation, such as one-line drawings, for each RAS that is likely
already be in the RAS-entity’s possession today. RAS-entities and their
associated RCs should therefore be able to begin the RAS review process with
only minimal lead time following the adoption of PRC-12-2. Texas RE would
further note that although RCs may need additional compliance resources to
perform the RAS reviews contemplated under PRC-12-2, the existing language in
PRC-12-2, R2 already provides RCs and RAS-entities with the flexibility to extend
the review period if necessary based on a “mutually agreed upon schedule.”
A similar rationale applies to the misoperation review and correction process in
PRC-12-2, R5. As the SDT notes, “[t]he correct operation of a RAS is important
for maintaining the reliability and integrity of the BES. Any incorrect operation of
a RAS indicates that the RAS effectiveness and/or coordination has been
compromised.” Texas RE agrees with this statement. In light of this fact,
however, Texas RE believes that RAS-entities should begin RAS operational
performance assessments following a RAS failure or misoperation immediately
upon adoption of PRC-12-2 in order to avoid a significant reliability gap.
If the SDT elects to retain an implementation period of any length, Texas RE
recommends that such implementation plan not apply to PRC-12-2, R4 and
R8. These requirements already have significant time periods for RAS-entities to
complete their compliance obligations embedded within them. For example,
RAS-entities have six years under PRC-12-2, R8 to complete initial functional
tests of their RAS (and 12 years for limited impact RAS if that definition is
retained). Given that PRC-12-2, R4 and R8 already provide extended
compliance horizons, Texas RE does not believe that additional time is necessary
to implement these requirements. Instead, the 6-full-calendar month period in
PRC-12-2, R4 and the six- and twelve-year periods in PRC-12-2, R8 should begin
on the effective date of PRC-12-2 itself.
Additionally, the Implementation Plan contains the same “limited impact”
language Texas RE has concerns about (see response to question 1).
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Wilson - Independent Electricity System Operator - 2 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Oshani Pathirane - Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1,
3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
Yes
Answer Comment:
Hydro One Networks Inc. would like to point out that Requirement R9 on Page
4/5 of the Implementation Plan does not stipulate a time fame by which an RC
that does not have a RAS database is required to populate one by.
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ben Engelby - ACES Power Marketing - 6 Group Information
Group Name:
ACES Standards Collaborators - PRC-012-2 Project
Group Member Name Entity
Region
Segments
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Mark Ringhausen
Old Dominion Electric
Cooperative
RFC
3,4
Ryan Strom
Buckeye Power, Inc.
RFC
4
Matt Caves
Western Farmers Electric
Cooperative
SPP
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
WECC
1,4,5
Kevin Lyons
Central Iowa Power Cooperative
MRO
1
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Voter Information
Voter
Segment
Ben Engelby
6
Entity
Region(s)
ACES Power Marketing
Selected Answer:
Yes
Answer Comment:
We agree with the SDT that the implementation plan is appropriate.
Document Name:
Likes:
0
Dislikes:
0
Phil Hart - Associated Electric Cooperative, Inc. - 1 Group Information
Group Name:
AECI
Group Member Name Entity
Region
Segments
Mark Ramsey
N.W. Electric Power Cooperative, SERC
Inc.
1
John Stickley
N.W. Electric Power Cooperative, SERC
Inc.
3
Kevin White
Northeast Missouri Electric Power SERC
Cooperative
1
Skyler Wiegmann
Northeast Missouri Electric Power SERC
Cooperative
3
Michael B Bax
Central Electric Power
Cooperative
SERC
1
Adam M Weber
Central Electric Power
Cooperative
SERC
3
Denise Stevens
Sho-Me Power Electric
Cooperative
SERC
1
Jeff L Neas
Sho-Me Power Electric
Cooperative
SERC
3
Walter Kenyon
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
SERC
1
Todd Bennett
Associated Electric Cooperative
Inc.
SERC
3
Matt Pacobit
Associated Electric Cooperative
Inc.
SERC
5
Brian Ackermann
Associated Electric Cooperative
Inc.
SERC
6
Voter Information
Voter
Segment
Phil Hart
1
Entity
Region(s)
Associated Electric Cooperative, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
No
Answer Comment:
ERCOT supports the comments submitted by the IRC SRC and provides these
additional comments.
The SDT should consider whether the standard should be clarified to address the
designation of “limited impact” RAS during the implementation period of PRC012-2.
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
No
Answer Comment:
Peak will see significant additional workload burden with this standard
implementation and can plan to be ready within 18 months.
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
MRO,SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
3. Revised Definition of SPS and its Implementation Plan: The drafting team revised the
definition of Special Protection System to cross-reference the revised definition of Remedial
Action Scheme. The Implementation Plan for the revised definition of Special Protection System
aligns with the effective date of the revised definition of Remedial Action Scheme. Do you agree
with the proposed definition and its implementation plan? If no, please provide the basis for your
disagreement and an alternate proposal.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Falsey - Invenergy LLC - 3 - FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
Yes
Document Name:
Likes:
0
Dislikes:
0
Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Yes
Answer Comment:
While it’s inferred from the standard, there should be an explicit statement in the
implementation plan that existing SPS implemented under the RRO standard do
not need to be re-approved by the RC.
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
Yes
Answer Comment:
We will appreciate if the Implementation Plan can also address the target date for
retirement/elimination of the term/acronym SPS from the NERC Glossary and
Standards. Wasn’t eliminating the usage of SPS one of the primary drivers for
recommending Remedial Action Scheme (RAS) as the preferred term when the
RAS/SPS definition was revised?
Document Name:
Likes:
0
Dislikes:
0
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Laura Nelson - IDACORP - Idaho Power Company - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Yes
Answer Comment:
In the future, NERC’s Reliability Standards Development Plan should have the
goal of eliminating “Special Protection System” or “SPS” from standards when
those standards are revised.
Document Name:
Likes:
5
Dislikes:
0
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Daniel Mason - City and County of San Francisco - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
William Temple - William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Greg Davis - Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Steve Wenke - Avista - Avista Corporation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Kenny - Eversource Energy - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Gowder - Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC
Group Information
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name Entity
Region
Segments
Paul Malozewski
Hydro One.
NPCC
1
Guy Zito
Northeast Power Coordinating
Council
NPCC
NA - Not
Applicable
Brian Shanahan
National Grid
NPCC
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY-ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability
Council
NPCC
7
Kathleen M. Goodman
ISO-New England
NPCC
2
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Michael Jones
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Voter Information
Voter
Segment
Ruida Shu
1,2,3,4,5,6,7
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rich Hydzik - Rich Hydzik On Behalf of: Bryan Cox, Avista - Avista Corporation, 5, 3, 1
Scott Kinney, Avista - Avista Corporation, 5, 3, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
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0
Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Wilson - Independent Electricity System Operator - 2 - NPCC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Oshani Pathirane - Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1,
3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Ben Engelby - ACES Power Marketing - 6 Group Information
Group Name:
ACES Standards Collaborators - PRC-012-2 Project
Group Member Name Entity
Region
Segments
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Mark Ringhausen
Old Dominion Electric
Cooperative
RFC
3,4
Ryan Strom
Buckeye Power, Inc.
RFC
4
Matt Caves
Western Farmers Electric
Cooperative
SPP
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
WECC
1,4,5
Kevin Lyons
Central Iowa Power Cooperative
MRO
1
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Voter Information
Voter
Segment
Ben Engelby
6
Entity
Region(s)
ACES Power Marketing
Selected Answer:
No
Answer Comment:
The SDT should eliminate the SPS definition in its entirety. An archived definition
could also reference the current definition by stating “see Remedial Action
Scheme.” There is no reason to keep SPS as an active glossary term. This will
only cause more confusion in the industry.
Document Name:
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0
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0
Phil Hart - Associated Electric Cooperative, Inc. - 1 Group Information
Group Name:
AECI
Group Member Name Entity
Region
Segments
Mark Ramsey
N.W. Electric Power Cooperative, SERC
Inc.
1
John Stickley
N.W. Electric Power Cooperative, SERC
Inc.
3
Kevin White
Northeast Missouri Electric Power SERC
Cooperative
1
Skyler Wiegmann
Northeast Missouri Electric Power SERC
Cooperative
3
Michael B Bax
Central Electric Power
Cooperative
SERC
1
Adam M Weber
Central Electric Power
Cooperative
SERC
3
Denise Stevens
Sho-Me Power Electric
Cooperative
SERC
1
Jeff L Neas
Sho-Me Power Electric
Cooperative
SERC
3
Walter Kenyon
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
SERC
1
Todd Bennett
Associated Electric Cooperative
Inc.
SERC
3
Matt Pacobit
Associated Electric Cooperative
Inc.
SERC
5
Brian Ackermann
Associated Electric Cooperative
Inc.
SERC
6
Voter Information
Voter
Segment
Phil Hart
1
Entity
Region(s)
Associated Electric Cooperative, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
MRO,SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
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0
4.
If you have any other comments that you haven’t already provided in response to the above
questions, please provide them here.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
na
Document Name:
Likes:
0
Dislikes:
0
John Falsey - Invenergy LLC - 3 - FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5 - RFC
Selected Answer:
Answer Comment:
We maintain our previous position that the draft standard is entirely deficient due
to the patchwork nature of responsibility for a RAS, especially when there are
multiple Owners of portions of the RAS. The standard appears it would be
effective where there is only one RAS entity. However, there is no mechanism for
overall coordination and responsibility for the case when there are multiple
owners. In this respect, the previous draft was superior in that it recognized there
needs to be a single RAS Owner that has overall responsibility for ensuring the
requirements of PRC-012-2 are met. There is no entity designated to take the
lead in developing the data needed for R1, including the technical studies needed
to describe system performance. A weak acknowledgement of the need for
collaboration among multiple entities is a statement in the R5 Rationale: “RAS-
entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance.” There is nothing in the
Standard as written that will drive the needed “directed collaboration” to bring
beneficial results in the analysis of RAS operations and any corrections needed.
Our recommendation is to restore the RAS-Owner entity (or RAS-Coordinator ?)
and to identify this entity as the Transmission Owner and/or Transmission
Planner having primary interest and technical capability to execute the technical
studies (steady state, dynamic, etc), and designate these to have lead or primary
responsibility for the Requirements. The individual RAS-entities with ownership
of related equipment would be responsible to participate in the requirements as
listed, under the umbrella of the primary entity.
Absent a Standard requiring a single entity to take charge of the development of
RAS, analysis of its operations, and development of needed CAP’s, it appears
unlikely that the Standard will actually produce meaningful results, nor an
improvement in reliability. This despite the great amount of effort that will be
required to ensure compliance.
Document Name:
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1
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0
Associated Electric Cooperative, Inc., 1, Hart Phil
Gul Khan - Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
In regards to R8 Oncor Electric Delivery does not differentiate between functional
testing of a protection system and functional testing of a RAS. This is an
unnecessary requirement, and any responsible entity will perform functional
testing of a RAS when maintaining the protection system components of a RAS.
Oncor recommends that an entity whose PRC-005-2 maintenance program
covers functional testing of its RASs does not have to comply with PRC-012-2
R8. The non protection system components of a RAS are tested when performing
maintenance under PRC-005. Hence adhering to the proposed R8 in PRC-012-2
will only require additional documentation while not positively affecting the
reliability of the BES.
In regards to R1 Oncor Electric Delivery believes the RAS information required in
attachment 1 contains more than is necessary for a review and cannot always be
obtained for every RAS. Also providing all this information is not required prior to
placing a protection system under PRC-005 in service so it should also not be
required under PRC-012-2.
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0
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0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
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0
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0
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
SRP appreciates the opportunity to comment on the proposed revisions to PRC012 and provides the following additional comments related tot he draft posted.
1) Similar to concerns with “limited impact”, “functionally modified” as written is an
unofficial defined term within the standard. SRP recommends defining the term
“functionally modified” and including it within the NERC Glossary of Terms.
2) Attachment 1 and 2 as originally presented were checklists. As currently
written, they are not. Rather they are itemized lists of information to be included
or assessment to be made. As written the Attachments 1 & 2 create ambiguity in
regards to what is expected from the submitter and reviewer.
3) Under R1, the identification within the rationale that “ideally, when there is
more than one RAS- entity for a RAS…” is not captured within the language of
the standard. SRP agrees with this intention, however recognizes that once the
rationale is removed from the standard, this will be lost. SRP recommends
adjusting the language of the standard or including the language within the
measure to more clearly indicate the intention of the SDT.
4) Under R3, the RAS entity that receives feedback is required to “resolve each
issue to obtain approval”. This language as written does not specify a resubmittal
of the information required under Attachment 1 and fails to reactivate the
timeframe identified for the reviewer under R3. SRP recommends adjusting the
language to “ resolve each issue and resubmit Attachment 1 information to the
reviewing RC to obtain approval…”.
5) Under R4, there is an inconsistent use of quotes around “limited impact” again
pointing to the previously discussed confusion created by imbedding an
unofficially defined term within the standard.
6) R^ has a singular/ plural inconsistency "Pursuant to the Requirements R5,
or..". This should be singular.
Similar to the issue identified under R1, R8 requires each entity to participate in
“performing” the functional test. This would require all partial owners to be
involved in the functional test of a RAS. Participation is vague and can result in
confusion over what would constitute participation. SRP recommends adjusting
the language to read “the RAS entity shall perform a functional test..”. This would
allow joint owners to coordinate the activities
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Meghan Ferguson - Meghan Ferguson On Behalf of: Michael Moltane, International Transmission
Company Holdings Corporation, 1
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
R4.1.3 and R4.1.4 – These requirements refer to ‘single component malfunction’
and ‘single component failure’ respectively. However, the standard does not
contain any identification or clarification of which types of components must be
included and which may be excluded in RAS evaluations. This deficiency could
be addressed by including text in the Supplemental Material section under
Requirement 4 that the drafting team developed for a response in its
Consideration of Comments for Draft 1 of PRC-012-2.
•
“An exhaustive list of components is not practical given the variety that
could be applied in RAS design and implementation. See Item 4a in the
Implementation Section of Attachment 1 in the Supplemental Material
section for typical RAS components for which redundancy may be
‐e
considered. The RAS
components were applied to put a RAS into service and which were
already present in the system before a RAS was installed. The RC will
make the final determination regarding which components should be
regarded as RAS components during its review”.
R5 – This requirement does not obligate RAS-entities to provide their results of
the operational performance analysis of a RAS event to impacted Transmission
Planners and Planning Coordinators. However, this action should be proposed in
the Supplemental Material section.
R6 – This requirement does not obligate RAS-entities to provide their Corrective
Action Plans to impacted Transmission Planners and Planning Coordinators.
However, this action should be proposed in the Supplemental Material section.
R8 - The purpose of Version 2 of PRC-005 was to consolidate all maintenance
and testing of relays under one Standard. Having RAS testing within PRC-012-2
would be contrary to that end. The NSRF proposes to address this concern as
follows:
•
Functional testing of RAS (as stated in Requirement 8 of PRC-012-2) is a
maintenance and testing activity that would be better included in the
PRC-005 standard. The present PRC-005-2 Reliability Standard is the
maintenance standard that replaces PRC-005-1, 008, 011 and 017 and
was designed to cover the maintenance of SPSs/RASs. However,
Reliability Standard PRC-005-2 lacks intervals and activities related to
non-protective devices such as programmable logic controllers. The
NSRF recommends that a requirement for maintenance and testing of
non-protective RAS components be added to a revision of PRC-005-6,
rather than be an outlying maintenance requirement located in the PRC012-2 Standard.
R8. Of the proposed Standard states: Each RAS
‐entity
performing a functional test of each of its RAS to verify the overall RAS
‐Protection Syst
performance and the proper operation of non
components. Please provide clarification that the word test and verify is aligned
with the definitions contained in the Supplementary Reference and FAQ, PRC005-2 Protection System Maintenance dated October 2012.
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Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Selected Answer:
Answer Comment:
a. The Standard Drafting Team gave examples of “functional modifications” in
the Rationale Box for R1. Seminole requests that these examples be moved into
the Standard language to make these examples more than mere suggestions by
the SDT, which would be the case if this language is left in the Application
Guidelines.
b. For Requirement R1, can the SDT confirm that each RAS-entity, even if the
entity is only a partial ower of a RAS, must submit a fully completed Attachment 1
submission?
c. For Requirement R3, if the RAS-entity disagrees with "issues" the RC
indicates, can the RAS-entity document technical reasons why the RAS-entity's
design is satisfactory or does the RAS-entity have to get REC approval?
d. Footnote 1 for Requirement 4 appears to state that the only existing limited
impact RAS are located in NPCC, ERCOT, and WECC. The footnote does not
appear to allow for existing limited impact RAS in other Regions, specifically the
FRCC. Seminole requests that the drafting team modify the language in the
Standard and footnote to clarify that existing RAS in the FRCC and other Regions
can also have existing limited impact RAS.
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0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Randi Heise - Dominion - Dominion Resources, Inc. - 5 Group Information
Group Name:
Dominion - RCS
Group Member Name Entity
Region
Segments
Larry Nash
Dominion Virginia Power
SERC
1
Louis Slade
Dominion Resources, Inc.
SERC
6
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Voter Information
Voter
Segment
Randi Heise
5
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
Dominion believes that the term “in-kind” included in Footnote 4, “Changes to
RAS hardware beyond in
‐kind repla
vague and suggests that the term be clarified such that the reader knows that
the replacement of an electromechanical relay with a microprocessor relay is
construed as an “in kind” replacement, as the drafting team noted in their
December 15th presentation. The concept of “In-kind” replacement could be
taken a step further. For example, a discrete ladder logic circuit that includes
contacts, overcurrent and voltage relays could be replaced entirely inside the
software logic of a multifunction device. From a black-box viewpoint, the old and
new RAS would be identical in function. Dominion also suggests for additional
consideration that the replacement of many discrete components with a single
multifunction component also be considered an “in kind” replacement so long as
for a given set of inputs the “black box” produces the same outputs as the
previous RAS would. In the case of a breaker failure event, the Standards
Drafting Team “SDT” indicates the need for RAS redundancy even though that
would be a double failure event (failure of the RAS and failure of the
breaker). Dominion suggests that it is sufficiently redundant to use the existing
breaker failure relay (non-redundant) to initiate both RAS schemes. This can be
accomplished by each RAS using a different contact off the breaker failure relay
that was separately fused.
Dominion suggests the SDT consider using a consistent measure of time, either
calendar months or full calendar days, for responding and reporting. For
example, Requirement 2 states: Each Reliability Coordinator that receives
‐f
Attachment 1 information pursuant to Requirement R1, shall, within four
calendar months of receipt, or on a mutually agreed upon schedule, perform a
review of the RAS in accordance with Attachment 2, and provide written feedback
to each RAS
‐entity.”
Whereas Requirement 4 states that: “Each RAS entity,
‐offuallRAS
calenoperation
d ar d aysor a failure of its RAS to
within 120
operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall:”
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Amy Casuscelli - Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
Answer Comment:
We agree with the footnote definition of “limited impact” RAS and the exceptions
stated in parts 4.1.3 and 4.1.6 of R4.
Usage of both RAS-owner and RAS-entity in the previous posting of the draft
standard was confusing – so we agree with the SDT’s solution to eliminate one of
them. We also agree that retaining the previous definition of RAS-owner as
Applicable Entity is more appropriate. However, we do not understand what is
the compelling need and/or the benefit of reassigning the RAS-owner definition to
the RAS-entity. Absent a rationale by the SDT for preferring RAS-entity, we
suggest using RAS-owner since it better aligns with the various owners
comprised in the definition.
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0
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Selected Answer:
Answer Comment:
Regarding the third bullet when describing Functional modifications; what does
"in-kind" mean? The description in the Supplemental Material describes it but TriState believes the phrase "preserves the original functionality" is more
appropriate. This is used in several places (Rationale for R1, Att. 1, and Att. 2, at
a minimum).
Regarding the fourth bullet when describing Functional modifications; we suggest
changing the language to read "...beyond correcting existing errors". The phrase
"error correcting" has other implications and is not described in the Supplemental
Material.
Tri-State would like to know what the SDT's intentions were when adding the
statement "The RC is not expected to possess more information or ability than
anticipated by their functional registration as designated by NERC" to the
Rationale for Requirement R2. We don't know why that was necessary.
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Laura Nelson - IDACORP - Idaho Power Company - 1 Selected Answer:
Answer Comment:
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0
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0
John Seelke - PSEG - 1,3,5,6 - NPCC,RFC
Group Information
Group Name:
PSEG
Group Member Name Entity
Region
Segments
Joseph Smith
Public Service Electric and Gas
RFC
1
Jeffrey Mueller
Public Service Electric and Gas
Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources &
Trade LLC
RFC
6
Voter Information
Voter
Segment
John Seelke
1,3,5,6
Entity
Region(s)
PSEG
NPCC,RFC
Selected Answer:
Answer Comment:
1. Suppose a RAS is intended to cause a generator to run-back under a
defined set of conditions. Further, suppose that the generator and the
RAS-entity that sends run-back signals to the generator’s DCS are
different (non-affiliated) companies. Is the generator’s DCS a part of the
RAS?
2. R4.2 should be expanded with respect to the entities a Planning
Coordinator “provides the results of the RAS evaluation including any
identified deficiencies.” PSEG believes that the results should also be
provided to non-RAS entities (i.e., TOs, GOs, and DPs) whose facilities
are impacted by the operation of a RAS.
Attachment 1 and R1 should be modified as follows for the reasons provided:
1. In many cases, a single RAS has multiple RAS entities. Attachment 1
should be modified so that each RAS entity’s components in the RAS are
clearly identified.
2. The entity responsible for providing the information required in
Attachment 1 Section II should be identified. For example, item II.6 and
III.4 should be completed by the Planning Coordinator (who has the
capability to provide that information) rather than the RAS entity. The
comments that PSEG submitted for the initial draft addressed this
concern and recommended that the RAS entity’s Transmission Planner
prepare this section; however, since the standard is applicable to
“Planning Coordinator,” that entity is more appropriate. In response to
PSEG’s comments, the SDT stated:
“The drafting team acknowledges that the need for a RAS and/or the
determination of RAS characteristics are most often identified through planning
studies performed by the Planning Coordinators or Transmission Planners. These
studies are included in the Attachment 1 information supplied to the Reliability
Coordinator (RC) for the RAS review and approval.”
PSEG unequivocally agrees with this comment. Therefore, R1 should be
modified to state that “each RAS entity and its Planning Coordinator shall provide
the information required of it in Attachment 1 ….”
With this change, Attachment 1 should be modified to identify which entity (RAS
entity or Planning Coordinator) is required to provide what information.
Other Attachment 1 items:
1. Items II.1 and II.2 are duplicative to I.4.e and I.4.f. Therefore, items I.4.e
and I.4.f should be deleted. Also, Items II.1 (contingencies and System
conditions) and II.2 (RAS action) should be stated so that each
contingency and System condition is linked to an expected RAS action
(assuming all RAS equipment operates properly). As a simplification, the
two items could be combined in to one item: “Each contingency and
System condition that the RAS is intended to remedy and the associated
RAS response.”
2. Item III.1 should have include be expanded to say “and documentation
showing that any multifunction device used to perform RAS function(s), in
addition to other functions such as protective relaying or SCADA, does
not compromise the reliability of the RAS when the device is not in ‐
service or is being maintained.” This is required to ensure that non-RAS
equipment that is essential to the successful operation of the RAS is not
inadvertently removed from service.
Document Name:
Likes:
5
PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG - PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG - Public Service Electric and Gas Co., 1, Smith Joseph
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
John Pearson - John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
Answer Comment:
Under Requirement R4.2 additional clarification regarding the as to the “reviewing
Reliability Coordinator”. We suggest changing the wording to the “impacted”
Reliability Coordinator from “reviewing” as shown below.
4.2. Provide the results of the RAS evaluation including any identified deficiencies
to
each impacted Reliability Coordinator and RAS
‐entity,
Transmission Planner and Planning Coordinator.
Under R5, each RAS entity must review any RAS operation whether the
operation was as designed or a there was an unintended or adverse BES
response. Under R6, wording calls for a Corrective Action Plan (CAP) to be
developed no matter what. We suggest clarifying wording under R6 as follows to
limit development of a CAP to when RAS operation caused an unintended or
adverse BES response.
R6. Each RAS
tity shall participate in developing a Corrective Action Plan
‐en
(CAP) when RAS operation caused an unintended or adverse BES response and
submit the CAP to its impacted Reliability Coordinator(s) within six full calendar
months…
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Daniel Mason - City and County of San Francisco - 5 Selected Answer:
Answer Comment:
Hetch Hetchy does not agree with the proposed change in the definition of a RAS
entity. HHWP believes that the definition of a RAS entity in the last posted version
of PRC-012 should be retained and that the RAS owner designated to represent
all RAS
‐owne
evaluation of RAS impacts is available to the appropriate reliability entities .The
proposed change in the definition of a RAS entitiy unnecessarily expands the
scope of entities involved in RAS evaluation and is likely to lead to duplication of
efforts, or reliabilty gaps. Having a single point of contact for RAS
coordination/management is the efficient and effective approach for ensuring that
Remedial Action Schemes (RAS) do not introduce unintentional or unacceptable
reliability risks to the Bulk Electric System.
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William Temple - William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Selected Answer:
Answer Comment:
The Rationale Box for Req. 1 contains important guidelines for when a review of
RAS is needed. These should be captured and retained in a standing
Guideline. Also, there should be a need to review a RAS when the settings that
initiate the RAS are changed.
In the Applicability section of Attachment 3, the three entities identified for
obligations to PRC-012-2 are explained with a concluding caveat that these
entities can collaborate to meet the requirements of the standard.
“The standard does not stipulate particular compliance methods. RAS
‐en
have the option of collaborating to fulfill their responsibilities for each applicable
requirement. Such collaboration and coordination may promote efficiency in
achieving the reliability objectives of the requirements; however, the individual
RAS
‐en
example, the individual RAS
‐e
single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement
R1 to initiate the RAS review material to the process.”
We request how this allowance will be included in the RSAW for this standard?
With regards to Req. 4.2, we suggest that the Planning Coordinator only needs to
provide evidence of the evaluation results to the RAS-entity if a deficiency is
identified. This will help reduce the compliance burden of submitting
documentation if the evaluation results are acceptable.
R6 should be clarified as proposed:
“Each RAS
‐entity
ing
a Corrective
shall participate
Action Plan
in develop
(CAP)
and submit the CAP to its reviewing Reliability Coordinator(s) within six full
calendar months of:”
Also, throughout the standard, references to days and months should be
standardized. There are references to 60 calendar months, 6 calendar months,
and 120 calendar days. These time periods should be expressed in either all
months or all days to maintain consistency throughout the standard.
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Greg Davis - Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Answer Comment:
There are multiple registered Planning Coordinators in GTC's Planning Area,
although we joint plan, we would like to propose a simple solution to ensuring that
each Planning Coordinator will become aware of any new or materially modified
RAS within GTC's Planning Area. Additionally the following rationale is provided
to make the basis for our recommendation:
· Not every PC is registered as an RC.
· There may be multiple PCs in 1 RC area
· PCs that do not own transmission assets may not be aware of new or
functionally modified RAS’s proposed by others and shared only with the RC
· A revision to R1 to include the Planning Coordinator as well is not an option,
because some RAS entity’s may not be aware of multiple PC registrations in their
area.
Therefore, GTC proposes the following new requirement to compliment the
obligations of the Planning Coordinator under requirement R4.
R10(proposed new requirement): Each Reliability Coordinator shall provide each
Planning Coordinator in their Reliability Coordinator area a copy of the RAS
database maintained in accordance with R9, at least once every twelve full
calendar months.
Additionally, GTC recommends a slight change to requirement R4 to compliment
the new proposed R10 requirement
R4. Each Planning Coordinator that receives a list of RAS’s pursuant to R10, at
least once every 60 full calendar months, shall:
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Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
•
To promote clarity and efficiency, AZPS suggests adding the following to
the Rational for Requirement R4 ““Ideally, for a RAS which is activated in
multiple Planning Coordinator areas, a mutually agreed upon Planning
Coordinator of one of the multiple Planning Coordinator areas shall
perform the R4 evaluation.”
•
Page 6, foot note 1 defines the limited impact RAS as that which cannot
“cause or contribute” to cascading etc. The word “contribute” should be
removed because it reduces clarity to the standard. The term “contribute”
is too broad and creates challenges to precisely evaluate.
•
Attachment 2 I. 6 states that a limited impact RAS is determined by the
RC. AZPS suggests modifying the language to “…limited impact RAS as
determined by the RC or through a regional review process.” This will
add flexibility to the implementation of the standard and/or allow for an
appeal process to be created, if needed.
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John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1 Selected Answer:
Answer Comment:
On page 53 of the redlined version of the proposed standard, in the Technical
Justifications for Attachment 1 Content Supporting Documentation for RAS
Review section, II. 6., there does not appear to be mention of the limited impact
exclusion.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
General Comment: Duke Energy suggests that the drafting team consider
placing the definition of “Remedial Action Scheme” in the standard for the industry
to reference while reviewing the proposal. The RAS definition is more complex
than most other definitions found in the NERC Glossary and compliance is
directly dependent on the proper application of the RAS definition to a particular
circumstance. Therefore, any future changes to the definition should be held to
the same review and approval process requirements as the RAS standard
itself. This would best be accomplished by incorporating the definition as an
integral part of the standard. Precedence for this approach already exists in other
NERC standards. Without this approach, it is possible to effectively change the
scope of the NERC standard without due process.
After further discussion, we have concerns regarding the RC being accountable
for the Remedial Action Scheme (RAS) review from a compliance perspective.
The RC is not able to or is not in the position to facilitate a review for technical
correctness of an RAS, and will be dependent upon a Planning Coordinator/RASentity to provide this information. On page 2 of the Question and Answer
document supplied by the drafting team on the project, it is stated;
“The RC is not expected to possess more information or ability than anticipated
by their functional registration as designated by NERC.”
We agree with this sentiment that an entity should not be held accountable for a
product that it is not able to or can readily provide. However, further down in the
same paragraph, the Q & A document reads;
“The RC may request aid in RAS reviews from other parties such as the Planning
Coordinator(s) or regional technical groups; however, the RC retains
responsibility for compliance with the requirement.”
The drafting team admits that the RC will need assistance from other entities to
perform or provide input for the RAS review. However, the RC will be held
accountable for the accuracy and technical input that goes into said
review. Requiring an entity to be accountable for information that it may not be
able to verify itself is problematic, and should be revisited. We recommend that
the drafting team consider adding language in the standard stating that the RC
will not be held responsible for the accuracy or content of the technical analysis
that is done by the Planning Coordinator/RAS-entity. Rather, the RC is
responsible for ensuring that an adequate review is conducted, whether it is an
individual review or coordinated review, merely for “identifying reliability-related
considerations relevant to various aspects of RAS design and implementation”,
as stated in the Technical Justification for Attachment 2 Content. This is a task
that the RC would be able to evaluate and verify itself without relying on the work
of another entity to achieve its compliance.
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Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Answer Comment:
ATC has several recommendations for improvement or clarification on the draft
Standard, for consideration by the SDT as listed below:
·
R4.1.3 and R4.1.4 – These requirements refer to ‘single component
malfunction’ and ‘single component failure’ respectively. However, the standard
does not contain any identification or clarification of which types of components
must be included and which may be excluded in RAS evaluations. This deficiency
could be addressed by including text in the Supplemental Material section under
Requirement 4 that the drafting team developed for a response in its
Consideration of Comments for Draft 1 of PRC-012-2.
“An exhaustive list of components is not practical given the variety that could be
applied in RAS design and implementation. See Item 4a in the Implementation
Section of Attachment 1 in the Supplemental Material section for typical RAS
‐e
components for which redundancy may be considered. The RAS
have a clear understanding of what components were applied to put a RAS into
service and which were already present in the system before a RAS was
installed. The RC will make the final determination regarding which components
should be regarded as RAS components during its review”.
·
R5 – This requirement does not obligate RAS-entities to provide their results
of the operational performance analysis of a RAS event to impacted Transmission
Planners and Planning Coordinators. However, this action should be proposed in
the Supplemental Material section.
·
R6 – This requirement does not obligate RAS-entities to provide their
Corrective Action Plans to impacted Transmission Planners and Planning
Coordinators. However, this action should be proposed in the Supplemental
Material section.
·
R8 - The purpose of Version 6 of PRC-005 was to consolidate all
maintenance and testing of relays under one Standard. Having RAS testing
within PRC-012-2 would be contrary to that end. ATC proposes to address this
concern as follows:
Functional testing of RAS (as stated in Requirement 8 of PRC-012-2) is a
maintenance and testing activity that would be better included in the PRC-005
standard. The present PRC-005-6 Reliability Standard is the maintenance
standard that replaces PRC-005-1, 008, 011 and 017 and was designed to cover
the maintenance of SPSs/RASs. However, the current Reliability Standard PRC005-6 lacks intervals and activities related to non-protective devices such as
programmable logic controllers. ATC recommends that a requirement for
maintenance and testing of non-protective RAS components be added to a
revision of PRC-005-6, rather than be an outlying maintenance
requirement located in the PRC-012-2 Standard.
If the requirement is not removed and placed in PRC-005 standard, then we
suggest that wording be added to R8 to refer the entity to meet the maintenance
and testing interval obligations in the latest version of the PRC-005 standard.
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2 Group Information
Group Name:
IRC Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Greg Campoli
NYISO
NPCC
2
Mark Holman
PJM
RFC
2
Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC
2
Voter Information
Voter
Segment
Charles Yeung
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
Selected Answer:
Answer Comment:
The rationale Box for R1 contains important guidelines for when a review of RAS
is needed. These should be captured and retained in a standing Guideline. Also,
there should be a need to review a RAS when the settings that initiate the RAS
are changed – which may or may not be covered by the list of circumstances
presented.
In the Applicability section of Attachment 3, the three entities identified for
obligations to PRC-012-2 are explained with a concluding caveat that these
entities can collaborate to meet the requirements of the standard.
“The standard does not stipulate particular compliance methods. RAS
tities
‐en
have the option of collaborating to fulfill their responsibilities for each applicable
requirement. Such collaboration and coordination may promote efficiency in
achieving the reliability objectives of the requirements; however, the individual
RAS ‐e
ntity must be able to demonstrate its participation for compliance. As an
example, the individual RAS
‐e
single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement
R1 to initiate the RAS review material to the process.”
We ask how will this allowance be included in the RSAW for this standard?
R6 should be clarified as proposed:
“Each RAS
and submit the CAP to its reviewing Reliability Coordinator(s) within six full
calendar months of:”
Also, throughout the standard, references to days and months should be
standardized. There are references to 60 calendar months, 6 calendar months,
and 120 calendar days. These time periods should be expressed in either all
months or all days to maintain consistency throughout the standard.
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‐e
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert A. Schaffeld
Southern Company Services, Inc. SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Voter Information
Voter
Segment
Pamela Hunter
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Answer Comment:
The owner of any protection scheme should be responsible for the correct design
and implementation of the scheme – RAS or not. Just like the design of switching
to create a blackstart cranking path by a TOP in EOP-005-2, Requirement 6 must
be verified by that TOP, the owner of the RAS should be held to the same
expectation that the RAS is correctly designed and implemented. If the SDT still
believes that some sort of review is required, then that review should be limited in
scope to reviewing the generic content of the RAS design and not delve into the
technical depth identified in some parts of Attachment 2.
Using the criteria outline by the SDT in its recent webinar, in addition to the
independence of the reviewer and geographic span, the team also mentioned
“expertise in planning, protection, operations, equipment”. The attributes of this
expertise to the level expected do not currently exist in most RC
organizations. RC’s are primarily operating entities (and even then primarily in
real-time) and not experts in planning (beyond the operating time frame),
protection or equipment. Transmission Owners, Transmission Operators and
Transmission Planners normally have that expertise. The FERC acknowledged
the limited RC technical expertise in evaluating details of restoration plans in its
Order 749, Paragraph 38 (“…basis on which a reliability coordinator rejects a
restoration plan will necessarily be based on generic engineering criteria…”). The
review of a RAS by an RC should not be held to a higher expectation due to
similar limited expertise with the equipment and systems involved in a RAS.
The “flexibility” for the RC granted in the requirement to designate a third party
would seem to immediately invalidate the original assumptions that the RC has
the compelling capability to adequately perform the review while meeting the
SDT’s characteristics of the reviewing entity. To allow this, while still requiring the
RC to be responsible for the review, seems like an improper administrative
burden and a potential compliance risk that the RC may assume because it had
to find an entity more qualified than itself to perform the review. If an RC is not
qualified to review all of the items in Attachment 2 then how can it be held
responsible for the results of the review?
Regarding the designation of a third party reviewer, clarification needs to be
made regarding what it means to “retain the responsibility for compliance.” Does
this simply mean that the review takes place or that there is some implied
resulting responsibility for the correct design and implementation that the RC is
now accountable for?
Finally, also regarding the designation of a third party reviewer, is the term “third
party” meant to be any entity not involved in the planning or implementation of the
RAS?
The alternative to using the RC? Although there appears to be a movement to
remove the RRO as a responsible entity from all standards, those organizations
through their membership expertise and committee structures more closely match
the characteristics stated by the SDT – expertise in
planning/protection/operations/equipment, independence by virtue of the diversity
of its members, wide area perspective, and continuity. If for some reason the
SDT, believes that the RRO still should not be involved then an alternative could
be the Planning Coordinator function which should have similar expertise to the
Transmission Planners that are to specify/design a RAS per the functional model
yet would have some independence which the SDT is looking for.
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Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1 Selected Answer:
Answer Comment:
Requirement 4 of the standard requires the PC to assess the scheme once every
60 fully calendar months but the standard doesn’t requires the RAS entity or RC
to provide the PC with the information required to complete this
assessment. Suggest adding an additional requirement for the RAS entity to
provide data required to assessment the RAS within 30 days of receiving
approval from the RC or within 30 calendar days of receiving a written request
from the PC. The PC should also be receiving the information provided to the
RC in R5.2, R6, R7.3.
In Attachment 1 the following information appears to be request twice under the
General and Description and Transmission Planning Information. If the drafting
team is intending different information be provided under the Description and
Transmission Planning Information, please consider revising the statement to
indicate what is expected.
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•
General item 4e and Description and Transmission Planning Information
item 1
•
General item 4f and Description and Transmission Planning Information
item 2
•
General item 4g and Description and Transmission Planning Information
item 5
Steve Wenke - Avista - Avista Corporation - 5 Selected Answer:
Answer Comment:
Moving the review of the RAS schemes up to the Reliabilty Coordinator level
does not seem to be the best solution. This responsibility should fall to the
Regional Entity.
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Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Selected Answer:
Answer Comment:
Why the drafting team has not applied the same approach for RAS components ?
Why non-protection system components associated to RAS cannot be subject to
PRC-005 to avoid functional tests like protection systems components ?
For consistency, all analysis and mitigation of BES protection systems and RAS
should be subject to the same standard. Hydro-Quebec TransEnergie suggests
removing R5 of PRC-012 and adding into PRC-004.
For consistency, all maintenance and testing requirements of BES protection and
control components, including RAS components, should be subject to the same
criteria. For instance, the requirement R8 of PRC-012 does not distinguish
monitored versus unmonitored devices.
Hydro-Quebec TransEnergie suggest removing R8 of PRC-012 and adding a
table of ‘components used for RAS’ in PRC-005.
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Mark Kenny - Eversource Energy - 3 Selected Answer:
Answer Comment:
Comments: Section 4.1.3 reads “Except for “limited impact”1 RAS, the possible
inadvertent operation of
the RAS, resulting from any single RAS component malfunction satisfies
all of the following:” Criteria 4.1.3.1 – 4.1.3.5 follow. Should this requirement also
pertain to a failure to operate, which is the more severe consequence of have a
single RAS component malfunction? Suggest the following wording
change: “Except for “limited impact”1 RAS, the possible inadvertent operation or
failure to operate of the RAS, resulting from any single RAS component
malfunction satisfies
all of the following:”
R6, second bullet item presently reads “Notifying the Reliability Coordinator
pursuant to Requirements R5, or”. To be clear, a CAP is only needed if the RAS
fails to operate or if during the evaluation of an operation, a deficiency is
confirmed. Suggest changing the language of this bullet to “Notifying the
Reliability Coordinator of a deficiency or failure to operate pursuant to
Requirements R5.2, or”
Use of the word “cannot” in footnote 1 is too restrictive and onerous for excluding
a RAS from having to comply with the single component failure requirements in
PRC-012-2. We suggest the Footnote 1 be revised to say:
“A RAS designated as “limited impact” has been demonstrated through studies to
not cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped
oscillations as a result of inadvertent operation or failure to operate. See
Attachment 2 for a description of the limited impact determination by the
Reliability Coordinator. A RAS implemented prior to the effective date of this
standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS
in WECC will be recognized as limited
impact for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4.”
R8 is vague and subject to interpretation. There are references in the
supplemental material that suggest verification all of the logic in a RAS PLC on a
periodic basis is required and yet in PRC-005, it’s clear that there is no need to
perform periodic maintenance on relay logic after it is commissioned. R8 also
does not consider fully monitored components of the RAS such as in PRC-005.
Attachment 1, II.6 language should be modified similar to comment above to
capture the possible RAS failure to operate due to a single RAS component
malfunction. Suggest new wording: “Documentation describing the System
performance resulting from the possible inadvertent operation or failure to operate
of the RAS, except for limited impact RAS, caused by any single RAS component
malfunction. Single component malfunctions in a RAS not determined to be
limited impact must satisfy all of the following:”
Attachment 1, III.3. statement appears to be only applicable to “limited impact”
RAS. Wording of this item should be modified to reflect this. A limited impact
RAS will still function correctly when a single component failure occurs or when a
single component is taken out for maintenance. In all cases, reliability of a RAS
scheme is impacted. It is not realistic to expect that reliability will not be
compromised. It is unclear what the intent of this statement is.
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Chris Gowder - Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
FMPA is confused as to why the drafting team considers 60 full calendar months
to be more consistent with PRC-014-0 than 5 calendar years, and views the later
as extending the schedule (60 months = 5 years). FMPA’s previous suggestion
(see below) was not to “extend this schedule”, but to make it more consistent with
the annual Planning Assessment requirements of the TPL standard. A change to
5 calendar years would allow the Planning Coordinator to conduct their RAS
evaluations in conjunction with their Planning Assessment, even if their process
concludes in a different month in year 5 than it did in year 1. Requiring 60
calendar months versus 5 calendar years creates an unnecessary compliance
burden that does not enhance reliability. The revision process should result in a
standard that is more consistent with other active standards than its previous
version, especially one that was never approved by FERC.
From the consideration of comments document…
“RAS Periodic Evaluations: Do you agree with the RAS planning evaluation
process outlined by Requirement R4? If no, please provide the basis for your
disagreement and an alternate proposal.
Selected Answer: Yes
Answer Comment: Recommend changing 60 full calendar months to 5 calendar
years, to allow the RAS evaluation to fit within the annual Planning Assessment
process which may vary from year to year.
Response: Thank you for your comment.
The drafting team based the 60 full calendar months schedule on the existing
PRC
‐01
five year. . .” The drafting team does not see a convincing reliability reason to
further extend this schedule and declines to make the suggested change.”
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Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
These comments are submitted on behalf of Louisville Gas and Electric Company
and Kentucky Utilities Company. (“LG&E/KU”). LG&E/KU are registered in one
region (SERC) for one or more of the following NERC functions: BA, DP, GO,
GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.
LG&E/KU strongly support the efforts the Standard Drafting Team has
undertaken to provide in PRC-012 clear and unambiguous performance
expectations and reliability benefits. LG&E/KU agree that the planning, design,
periodic review, analysis and testing of SPS/RAS schemes are each essential
components of maintaining BES reliability and that revising PRC-012 is a
necessary and critical step towards that end.
LG&E/KU note that in Section 4 - Applicability of the latest draft of PRC-012, the
functional entity “Planning Coordinator” has replaced “Transmission Planner.”
LG&E/KU support this change. However, while the current draft standard requires
the Planning Coordinator to periodically review SPS/RAS schemes within the
PC’s planning region, the draft standard provides no role for the PC in approving
any corrective action plan(s) developed to mitigate whatever threat(s) to BES
reliability the PC’s periodic review may have revealed. Moreover, and perhaps
more importantly, there is likewise no requirement that the PC approve planned
new or modified SPS/RAS schemes to insure consistency with procedures,
protocols, and modeling methodology utilized with the relevant planning region.
These omissions make it more difficult for the Planning Coordinator to coordinate
and integrate the “transmission facility and service plans, resource plans, and
protection system plans among the Transmission Planner(s) and Resource
Planner(s) within its area of purview.”[1]
LG&E/KU recognize that in some larger planning regions the Planning
Coordinator (“PC”) function may reside within the same organizational entity as
the Transmission Owner (“TO”) or Reliability Coordinator (“RC”) functions. PRC012, however, should function to promote and maintain BES reliability regardless
of how the TO, PC and RC functions are distributed between organizational
entities. Accordingly, LG&E/KU offer for the SDT’s consideration the following
changes to the draft requirements:
Requirement R1
Prior to placing a new or functionally modified RAS in
‐servic
existing RAS, each RAS
‐entity sh
Attachment 1 for review to the Reliability Coordinator(s) in consultation with the
Planning Coordinator where the RAS is located.
Requirement R2
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with
Attachment 2, and provide written feedback developed in consultation with the
Planning Coordinator to each RAS
‐entity.
Requirement R3
Prior to placing a new or functionally modified RAS in
‐servic
existing RAS, each RAS ‐
entity that receives feedback from the reviewing
Reliability Coordinator(s) identifying reliability issue(s) shall resolve each issue to
obtain approval of the RAS from the RAS-entity’s Planning Coordinator and each
reviewing Reliability Coordinator.
Requirement R5.2
Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s) and Planning Coordinator.
Requirement R6
Each RAS
Planning
‐entity shall
Coordinator
participate in
and Reliability Coordinator in developing a Corrective Action Plan (CAP) and
submit the CAP to the RAS-entity’s Planning Coordinator and Reliability
Coordinator(s) within six full calendar months of:
Requirement R7.3
Notify each reviewing Reliability Coordinator and Planning Coordinator if CAP
actions or timetables change and when the CAP is completed.
[1] NERC Reliability Functional Model Technical Document — Version 5, at p.10.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC
Group Information
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name Entity
Region
Segments
Paul Malozewski
Hydro One.
NPCC
1
Guy Zito
Northeast Power Coordinating
Council
NPCC
NA - Not
Applicable
Brian Shanahan
National Grid
NPCC
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY-ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability
Council
NPCC
7
Kathleen M. Goodman
ISO-New England
NPCC
2
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Michael Jones
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Voter Information
Voter
Segment
Ruida Shu
1,2,3,4,5,6,7
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
R9 as written requires an update to the database to be made every 12 months.
The Measure requires evidence that the database was updated. This would not
address the situation where no update to the database was required because
information did not change.
Reliability Standards usually use the phrase “review the information in the
database and update as necessary”. Then the Measure becomes to present
evidence that the review occurred and if a change occurred then the database
was updated.
Section 4.1.3 reads “Except for “limited impact”1 RAS, the possible inadvertent
operation of the RAS, resulting from any single RAS component malfunction
satisfies all of the following:” Criteria 4.1.3.1 – 4.1.3.5 follow. Should this
requirement also pertain to a failure to operate, which is the more severe
consequence of have a single RAS component malfunction? Suggest the
following wording change: “Except for “limited impact”1 RAS, the possible
inadvertent operation or failure to operate of the RAS, resulting from any single
RAS component malfunction satisfies all of the following:”
R6, second bullet item presently reads “Notifying the Reliability Coordinator
pursuant to Requirements R5, or”. To be clear a CAP is only needed if the RAS
fails to operate or if during the evaluation of an operation, a deficiency is
confirmed. Suggest changing the language of this bullet to “Notifying the
Reliability Coordinator of a deficiency or failure to operate pursuant to
Requirements R5.2, or”
Use of the word “cannot” in footnote 1 is too restrictive and onerous for excluding
a RAS from having to comply with the single component failure requirements in
PRC-012-2. We suggest the Footnote 1 be revised to say:
“A RAS designated as “limited impact” has been demonstrated by studies to not
cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped
oscillations as a result of inadvertent operation or failure to operate. See
Attachment 2 for a description of the limited impact determination by the
Reliability Coordinator. A RAS implemented prior to the effective date of this
standard that has been through the regional review process and designated as
Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4.”
R8 is vague and subject to interpretation. There are references in the
supplemental material that suggest maintenance checking all of the logic in a
PLC on a periodic basis is required and yet in PRC-005, it’s clear that there is no
need to perform periodic maintenance on relay logic. R8 also does not consider
fully monitored components of the RAS such as in PRC-005.
Attachment 1, II.6 language should be modified similar to comment above to
capture the possible RAS failure to operate due to a single RAS component
malfunction. Suggest new wording: “Documentation describing the System
performance resulting from the possible inadvertent operation or failure to operate
of the RAS, except for limited impact RAS, caused by any single RAS component
malfunction. Single component malfunctions in a RAS not determined to be
limited impact must satisfy all of the following:”
Attachment 1, III.3 statement appears to be only applicable to “limited impact”
RAS. Wording of this item should be modified to reflect this. A limited impact
RAS will still function correctly when a single component failure occurs or when a
single component is taken out for maintenance. In all cases, reliability of a RAS
scheme is impacted. It is not realistic to expect that reliability will not be
compromised. It is unclear what the intent of this statement is.
While we support the proposed standard as presented, the word “participate” in
Requirements R5, R6 and R8 can lead to confusion and may result in no entities
being held responsible for initiating or leading the required tasks. As written, the
RAS Entity needs only to participate in such tasks, but it is unclear on whose
tasks are they or who leads these tasks.
We suggest remove the word “participate” from R5, R6 and R8 so that the RAS
Entity is held responsible for analyzing the RAS operational performance in R5,
developing a CAP in R6, and conducting functional test in R8. Note that the
wording in the VSLs for R5, R6 and R8 clearly indicates that the RAS Entity is
responsible for these tasks. Hence, the word “participate” in the above-mentioned
three requirements is unnecessary and confusing.
We respectfully requests the STD to consider its previous comment; we believe
that RAS should be reviewed and approved in both the planning and operating
horizons by the designated entities within whose area(s) the Facility (ies) the RAS
is designed to protect reside.
We believes that the term “in-kind” included in Footnote 4, “Changes to RAS
hardware beyond in
‐kind
suggests that the term be clarified such that the reader knows that the
replacement of an electromechanical relay with a microprocessor relay is
construed as an “in kind” replacement, as the drafting team noted in their
December 15th presentation. The concept of “In-kind” replacement could be
taken a step further. For example, a discrete ladder logic circuit that includes
contacts, overcurrent and voltage relays could be replaced entirely inside the
software logic of a multifunction device. From a black-box viewpoint, the old and
new RAS would be identical in function. We also suggests for additional
consideration that the replacement of many discrete components with a single
multifunction component also be considered an “in kind” replacement so long as
for a given set of inputs the “black box” produces the same outputs as the
previous RAS would. In the case of a breaker failure event, the Standards
Drafting Team “SDT” indicates the need for RAS redundancy even though that
would be a double failure event (failure of the RAS and failure of the
breaker). We suggests that it is sufficiently redundant to use the existing breaker
failure relay (non-redundant) to initiate both RAS schemes. This can be
accomplished by each RAS using a different contact off the breaker failure relay
that was separately fused.
We suggests the SDT consider using a consistent measure of time, either
calendar months or full calendar days, for responding and reporting. For
example, Requirement 2 states: Each Reliability Coordinator that receives
‐f
Attachment 1 information pursuant to Requirement R1, shall, within four
calendar months of receipt, or on a mutually agreed upon schedule, perform a
review of the RAS in accordance with Attachment 2, and provide written feedback
to each RAS
‐entity.”
Whereas Requirement 4 states that: “Each RAS entity,
‐ fu ll of
days
calen
a RAS
d ar operation or a failure of its RAS to
within 120
operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall:”
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Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
Reclamation appreciates the drafting team’s consolidation of the terms RAS ‐
owner and RAS
‐e
Transmission Owner, Generator Owner, or Distribution Provider that owns all or
part of a RAS.
Reclamation also agrees with the drafting team’s update to Requirement R6 that
‐
each RAS
this collaboration will promote awareness of RAS degradation and the efforts and
timetables to return the RAS to service.
Reclamation supports the proposed change to the definition of SPS.
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Rich Hydzik - Rich Hydzik On Behalf of: Bryan Cox, Avista - Avista Corporation, 5, 3, 1
Scott Kinney, Avista - Avista Corporation, 5, 3, 1
Selected Answer:
Answer Comment:
PRC-012-2 includes some very positive changes for the industry.
In R4.1.3, footnote 1 defines a “limited impact” RAS which does not require
designing to a “no single point of failure” standard. It is a good thing to have this
defined in a NERC standard.
Functional testing requirements defined to be every six years (R8). This is
reasonable.
Evaluation of the need and performance of a RAS every six years is reasonable
(R4).
However, there are concerns that prevent an “affirmative” vote for this standard.
The Reliability Coordinator is a function is defined as:
“The entity that is the highest level of authority who is responsible for the Reliable
Operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric
System, and has the operating tools, processes and procedures, including the
authority to prevent or mitigate emergency operating situations in both next-day
analysis and real-time operations. The Reliability Coordinator has the purview
that is broad enough to enable the calculation of Interconnection Reliability
Operating Limits, which may be based on the operating parameters of
transmission systems beyond any Transmission Operator’s vision.”
This supports the concept of the RC reviewing the functionality and intended use
of a RAS. However, a detailed RAS review also includes a design review of the
RAS components and overall system design. This includes, but is not limited to,
substation engineering, relay protection and design, telecommunication design
and performance, and individual TOP operating practices. The RC’s are familiar
with the overall operation and performance of the BES. The RC’s skill set
generally does not include those technical specialties required for a detailed
review of the design of a RAS.
This follows that the evaluation of a RAS misoperation should be performed by a
different entity than the RC. While the RC certainly can evaluate the performance
of the RAS and identify that a misoperation occurred, the RC’s skill set does not
allow for a thorough review of the RAS problem or potential solutions. Further,
implementing a Corrective Action Plan under the supervision of the RC does not
seem appropriate. This places the RC in an engineering, maintenance, and
enforcement role that does not appear to be with the RC function.
The intent of the standard is sound. Implementation among the Reliability Entities
needs further development.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
Degraded RAS
As Texas RE mentioned in the comments for the initial ballot, Texas RE
recommends a requirement to report the degraded RAS to the RC. Texas RE
noticed the referenced Standards/Requirements (i.e., Supplemental Material
indicates PRC-001 R6 and TOP-001-2 R5) are either being retired or are not
explicit enough to ensure that the reliability of the system is maintained for those
who should have situational awareness. PRC-001 R6 is being retired and
translated to TOP-001-3 R10 and R11 which applies to ONLY the TOP and BA
not the RC. While TOP-003-3 states a BA and TOP “shall distribute its data
specification to entities that have data required by the” respective functions and
analysis (e.g., Real-time monitoring, Operational Planning Analyses), there is no
requirement to provide the RAS status to the RC.
Requirement R8
Texas RE is concerned introducing a six year functional testing requirement for a
RAS is too long to ensure reliability of a system because reliability is at stake for
the RAS to be in place. This extended timeframe may disregard PRC-005
components that may have shorter timeframes for maintenance or cause
confusion to the entities responsible for said maintenance. While the RAS-entity
will have PRC-005 obligations, it should not be considered the same as functional
testing of the RAS if the PRC-005 components are ignored, overlooked, or not
reviewed. Coordinated functional testing should be required for multi-RAS-entity
owned RASs. Without coordination, there is not a clear reliability path to ensure
overall performance and the proper operation of ALL RAS components.
Texas RE seeks clarity on the rationale for Requirement R8. It does not seem to
reflect a coherent approach to reliability when discussing resetting the “test
interval clock for that segment”. The Requirement is written for the RAS not
segments of the RAS. The phrase “of its” that was added increases ambiguity
and may cause confusion among RAS-entities in a multi-owned component
RAS. Texas RE recommends requiring coordination of functional testing for
RASs with components owned by more than one RAS-entity. Individualized noncoordinated functional testing of RAS components will not be a functional test of
the RAS.
Full Calendar Months
The SDT introduces a new term “full calendar months” that is not defined and is
inconsistent with other Reliability Standards. Texas Re recommends the SDT
provide the definition within the auspices of the Standards process while
considering other definitions already in place (such as “Calendar Year” in PRC005-2).
Corrective Action Plan
Texas RE recommends revising PRC-12-2, R7 to place at least minimal criteria
around modifications to Corrective Action Plans (CAP) or corresponding CAP
timetables. As currently drafted, PRC-12-2, R7 could be interpreted to permit
RAS-entities to perpetually update their CAPs if “actions or timetables change”
and then merely notify the RC of such changes. Texas RE recommends that the
SDT consider some minimal criteria that RAS-entities must satisfy in order to
update a CAP under PRC-12-2, R7.2. For instance, PRC-12-2, R7.2 could be
revised to read: “Update the CAP for any reasonable changes in the required
actions or implementation timetable.” In turn, PRC-12-2, R7.3 could be revised to
read: “Notify each reviewing Reliability Coordinator and provide a reasoned
justification for changes in CAP actions or timetables, and notify each reviewing
Reliability Coordinator when the CAP is completed.”
RAS-entity definition
The current draft of PRC-12-2 defines the term “RAS-entity” in the Technical
Justifications for Requirements section. Texas RE recommends that the SDT
consider incorporating this definition into the language of PRC-12-2 itself or into
the NERC Glossary of Terms.
Misoperations
In Requirement R5, what constitutes a RAS operation or misoperation? The
NERC SPCS created a draft template in 2014 for reporting RAS operations and
misoperations where they defined a misoperation as “Failure to Operate”,
“Unnecessary Operation”, “Unintended System Response”, and “Failure to
Mitigate”. These were draft terms and have not been incorporated into any
Standard or the NERC Glossary. Arming and disarming of a RAS were not
included in the SPCS RAS template. The items listed in 5.1.1 through 5.1.4
somewhat mirror the SPCS RAS template, is it the SDT’s intent that 5.1.1 through
5.1.4 are intended to be the definition of a RAS operation/misoperation? If so,
Texas RE suggests these would be better suited in the NERC Glossary than
within the Standard.
Also reporting of Misoperations for Protection Systems will be contained with the
Section 1600 Data Request for PRC-004. There is no requirement within PRC012 or the Section 1600 data request for reporting Misoperations of a RAS to the
Regional Entities or NERC. Texas RE recommends the SDT consider this.
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Dennis Chastain - Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6,
1, 5, 3
Error: Subreport could not be shown.
Selected Answer:
Answer Comment:
1. Numerous entities, including TVA, have previously commented that the
responsibility for reviewing and approving new or functionally modified RAS
schemes belongs with the Planning Coordinator and not the Reliability
Coordinator. According to the NERC Reliability Functional Model - Version 5, the
Planning Coordinator is defined as the, “…entity that coordinates, facilitates,
integrates and evaluates (generally one year and beyond) transmission facilities
and services plans, and resource plans within a Planning Coordinator area and
coordinates those plans with adjoining Planning Coordinator areas.” The model
specifically includes the evaluation of transmission facilities in the planning
horizon. Conversely, the Reliability Coordinator is responsible for maintaining the
Real-time reliability of the Bulk Electric System. It was never contemplated that
the Reliability Coordinator would have oversight over the planning of the Bulk
Electric System or the entities responsible for Bulk Electric System planning. The
drafting team’s response to TVA’s comments states that the Reliability
Coordinator has the “widest-area reliability perspective of all functional entities”
and that the “NERC Functional Model is a guideline” and does not preclude the
drafting team from addressing functions not described in the Functional
Model. From TVA’s perspective, however, the proposed standard, as written, is
in direct conflict with the Functional Model, and requires a compelling reason to
justify the deviation. The facts that there are fewer Reliability Coordinators (as
opposed to Planning Coordinators) and that the Reliability Coordinators have the
“widest-area view” do not support a significant deviation from the Functional
Model. Moreover, such analysis would beyond the normal Reliability Coordinator
functions, the Reliability Coordinators would not have the expertise to conduct
RAS analysis in the planning horizon. Simply put, Reliability Coordinators do not
have trained personnel or the appropriate tools to complete a comprehensive
assessment. Planning Coordinators have oversight over all other aspects of
planning of the Bulk Electric System, and there is no reason to treat Remedial
Action Schemes differently.
R6 requires the “RAS-entity” to develop Corrective Action Plans if there is a
deficiency in its 5-year RAS evaluation (R4), its post-event analysis (R5), or its 6year functional testing (R8), and to submit those Corrective Action Plans to the
Reliability Coordinator for review. The proposed standard, however, does not
give the Reliability Coordinator any authority to approve or deny the Corrective
Action Plan. If the Corrective Action Plan is inadequate or changes the RAS to
cause a negative impact on a wider area of the BES, the Reliability Coordinator
must be able to reject the Corrective Action Plan and require a revised plan.
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Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC
Selected Answer:
Answer Comment:
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Eric Olson - Transmission Agency of Northern California - 1 Selected Answer:
Answer Comment:
TANC appreciates the drafting team’s response to our prior comments and the
corresponding changes to the standard regarding the potentially overlapping
responsibilities of multiple Transmission Owners, Generator Owners and
Distribution Providers that each own portions of a single RAS. In its response to
TANC’s prior comments, the drafting team stated that each RAS-entity “is
responsible only for its RAS components.” The second draft of the standard is
not so clear on this issue, however, as the requirements only refer to each RASentity’s responsibility for “its RAS”. TANC requests that NERC replace “its RAS”
with “its RAS components” in the requirements of the standard to clarify the
responsibilities of each party. TANC believes that inserting this distinction into
the language of the requirements would more clearly convey that multiple parties
may have compliance responsibility for their respective “components” of a single
RAS, but each party is not responsible for the entirety of the RAS.
TANC notes that the “Reliability Standard PRC-012-2 Remedial Action Schemes
Question & Answer Document” document dated November 2015 appears to
incorrectly reference the Transmission Owner (TO) function in the first paragraph
of Section 3. References in that paragraph were made to TO roles and
responsibilities that are purportedly established within standards TOP-001-3 and
IRO-005-4, but those two standards establish roles and responsibilities for the
Transmission Operator (TOP) function, not the TO function.
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Mark Wilson - Independent Electricity System Operator - 2 - NPCC
Selected Answer:
Answer Comment:
While we support the proposed standard as presented, the word
“participate” in Requirements R5, R6 and R8 can lead to confusion and may
result in no entities being held responsible for initiating or leading the
required tasks. As written, the RAS Entity needs only to participate in such
tasks, but it is unclear on whose tasks are they or who leads these tasks.
We suggest to remove the word “participate” from R5, R6 and R8 so that
the RAS Entity is held responsible for analyzing the RAS operational
performance in R5, developing a CAP in R6, and conducting functional test
in R8. Note that the wording in the VSLs for R5, R6 and R8 clearly indicates
that the RAS Entity is responsible for these tasks. Hence, the word
“participate” in the above-mentioned three requirements is unnecessary
and confusing.
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Oshani Pathirane - Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1,
3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
Answer Comment:
While Hydro One Networks Inc. is generally in support of the direction the
standard takes and although the third revision (Draft 2- November 2015) presents
improvement (with the introduction of the concept of “limited impact RAS” and
recognition of RAS typing), requirement R8 and several choices in wording
remain a concern. Hydro One believes that a level of testing similar to that
required in the PRC-005 series would be more appropriate for R8. With a level of
testing specified in Comment #1 below, a high VRF, similar to that designated in
the PRC-005 series would be appropriate and hence although Hydro One has
cast a negative ballot on the standard, we are in support of the poll associated
with the VRFs and VSLs. We hope the comments provided below will be of
added value to the drafting team:
1. R8 is vague and subject to interpretation. There are references in the
supplemental material that suggest maintenance and checking of all the logic in a
PLC on a periodic basis is required, and yet, in PRC-005, it is clear that there is
no need to perform periodic maintenance on relay logic. For monitored
components, such as microprocessor relays, the “verification of settings [as]
specified” in PRC-005 (i.e., performing a settings compare) should be sufficient
rather than implying that all logic needs to be re-verified. For RAS not designated
as limited-impact, R8 does not distinguish between monitored and unmonitored
components of the RAS such as distinguished in PRC-005, which would allow a
RAS-entity to have a 12-year maintenance interval for monitored components.
2. R5.1 – The usage of the term “[p]articipate” does not define
accountability. The standard should clearly identify who is accountable for what
activity. For consistency, we suggest using verbiage similar to that used in PRC004-4’s description of accountabilities in the case of owning Shared Protection
Systems.
3. R5.1.3 & R5.1.4 are related to performance of RAS and its impact on the
BES. This assessment is better suitable for the PC or RC to conduct.
4. R5.2 – “Each RAS-entity shall provide results (…) to RC”. In the case that a
RAS is owned by more than one entity, it is unclear from the verbiage which entity
is accountable to communicate with the RC and maintain evidence of such
activity. The standard should clearly identify who is accountable for what
activity. For consistency, we suggest using verbiage similar to that used in PRC004-4’s description of accountabilities in the case of owning Shared Protection
Systems.
5. R6 - “ Each RAS-entity shall participate” - Similar to the comments submitted
above for R5, the usage of the term “[p]articipate” does not define
accountability. The standard should clearly identify who is accountable for what
activity. For consistency, we suggest using verbiage similar to that used in PRC004-4’s description of accountabilities in the case of owning Shared Protection
Systems.
6. “Each RAS-entity shall submit the CAP to RC” - Similar to the comments
submitted above for R5, in the case that a RAS is owned by multiple entities, it is
unclear from the verbiage which entity is accountable to communicate with the
RC and maintain evidence of such activity.
7. R5 – It is unclear from the wording whether the RAS-entity would
“[p]articipate in analyzing the RAS operational performance” with the RC, or only
mutually agree upon a schedule for such activity with the RC.
8. R4.1.4 - When a RAS is used to respond to an event, e.g. category P1 in
TPL-001-4, its failure should be considered to be a more severe event, just as in
TPL-001-4, the failure of a breaker or protection relay following a P1 event is
recognized as “Multiple Contingency” (category P3 and P4). For this reason, the
system performance with a RAS failure should not be required to meet the exact
same requirements as those for the original event (defined in TPL-0014). Therefore, we suggest deleting R4.1.4 and instead revising R4.1.3 to read
“Except for “limited impact”1 RAS, the possible inadvertent operation of the RAS,
or failure of the RAS to operate, resulting from any single RAS component
malfunction satisfies all of the following:”
9. RAS-entity: The standard should clearly define accountabilities in the case of
a RAS scheme being owned by multiple entities.
10. R2 – We suggest specifying which entity the RC will be mutually agreeing
upon a schedule with: “on a schedule mutually agreed upon with the RASentity,….”
Hydro One Networks Inc. also generally supports the comments the NPCC has
submitted.
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
R2: BPA maintains that the allowance of up to four full calendar months for the
RC to perform the RAS review is unreasonable and not in line with current
regional practice.
Currently in WECC, RAS information for new or functionally modified schemes
(this information is equivalent to Attachment 1 and 2) is provided two weeks in
advance of scheduled WECC RAS RS meetings. At those meetings, all details of
the RAS are presented, reviewed, and approved/disapproved. The review is at
the final stages of the design process, just prior to construction/energization. By
requiring Attachment 1, and Attachment 2, and allowing the RC four full calendar
months review time, it appears that four months is being added to the entire
process of placing a RAS in service. This additional four month delay may
constrain the energization of variable generation resources.
Regarding Attachment 2: “The RC review is not limited to the checklist items
and the RC may request additional information on any aspect of the RAS as
well as any reliability issue related to the RAS.” BPA believes this presents
an open-ended opportunity to increase the four month review window, because
you can’t go in service without prior approval of the RAS.
Attachment 2. II. 2. “The timing of RAS actions(s) is appropriate to its BES
performance objectives.” This makes sense, but often timing of a RAS cannot
be proven until the RAS is built and functionally tested. Historically in WECC, you
are aware of the timing constraints required for RAS operation, you provide an
estimate of the timing, and you’re provided “conditional approval” to go
operational with a future action item presented to the WECC RAS RS that
validates the timing is within constraints. Item 2 implies that a RAS-entity has to
prove the timing prior to going in service, which isn’t reasonable. That basically
means that the RAS-entity has to build the scheme, test it, and then go get it
approved.
Attachment 2. II. 4. “The RAS design facilitates periodic testing and
maintenance.” BPA believes this is subjective; does this mean that the RC
would require a standard method for periodic testing and maintenance? This
appears open to interpretation.
The four full calendar months appears to create the opportunity for a large
increase in workload and back and forth discussion between the RC and the
utility designing the RAS.
R3: BPA proposes the requirement allow for conditional approval.
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Ben Engelby - ACES Power Marketing - 6 Group Information
Group Name:
ACES Standards Collaborators - PRC-012-2 Project
Group Member Name Entity
Region
Segments
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
Shari Heino
Brazos Electric Power
Cooperative, Inc.
TRE
1,5
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Mark Ringhausen
Old Dominion Electric
Cooperative
RFC
3,4
Ryan Strom
Buckeye Power, Inc.
RFC
4
Matt Caves
Western Farmers Electric
Cooperative
SPP
1,5
John Shaver
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
WECC
1,4,5
Kevin Lyons
Central Iowa Power Cooperative
MRO
1
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Voter Information
Voter
Segment
Ben Engelby
6
Entity
Region(s)
ACES Power Marketing
Selected Answer:
Answer Comment:
(1) We agree with the SDT’s consolidation of the reliability objectives of the six
existing RAS/SPS related standards into one standard PRC-012-2.
(2) The SAR for revising TPL-001-4 for single points of failure may overlap with
PRC-012-2. We recommend the SDT meet with the SAR team to discuss the
scope and potential for overlap that could lead to double jeopardy. We
recommend that NERC staff also research this issue.
(3) RAS-entity causes confusion for entities that have joint ownership of a
RAS. We recommend the SDT develop guidance to support the requirements
and expectations for joint owners to meet compliance. For RAS with multiple
RAS-entities, who is responsible for overall coordination to assure complete and
consistent data submittals in order to meet compliance with this standard? The
SDT has left this silent, which may result in joint entities not cooperating, not
sharing documentation, etc.
(4) Corrective Action Plans need to be clarified as to what triggers would qualify
as a “deficiency” that would require a CAP to be developed. We also have
concerns relating to coordination of CAPs that are developed for a jointly-owned
RAS.
(5) We believe the VSLs for this standard could be better defined. The
incremental scale between one criteria (e.g., R4 has 60, 61, 62, 63 calendar
months for ranges from Lower to Severe) to the next for several VSLs are too
condensed. We also believe a graduated scale for Requirements R1 and R3
could be provided.
(6) We agree that the RC is the best-suited entity to perform the RAS
reviews. However, we recommend that the SDT actively work with RCs to ensure
they are aware of the proposed requirements and have the resources to support
them.
(7) We agree that the PC has a broader view compared to the TP and is the
proper entity for RAS periodic evaluations.
(8) Finally, we ask NERC to consider the holiday schedule when posting
standards for comment. There are several industry groups that coordinate
comments a week or two prior to final submission to the SDT, and having to
coordinate comments over the holidays is difficult with vacation schedules. We
ask the drafting teams to consider delaying posting so the deadline is the second
or third week in January, allowing the industry groups enough time to coordinate
during the weeks prior to the due date.
(9) Thank you for the opportunity to comment.
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Phil Hart - Associated Electric Cooperative, Inc. - 1 Group Information
Group Name:
AECI
Group Member Name Entity
Region
Segments
Mark Ramsey
N.W. Electric Power Cooperative, SERC
Inc.
1
John Stickley
N.W. Electric Power Cooperative, SERC
Inc.
3
Kevin White
Northeast Missouri Electric Power SERC
Cooperative
1
Skyler Wiegmann
Northeast Missouri Electric Power SERC
Cooperative
3
Michael B Bax
Central Electric Power
Cooperative
SERC
1
Adam M Weber
Central Electric Power
Cooperative
SERC
3
Denise Stevens
Sho-Me Power Electric
Cooperative
SERC
1
Jeff L Neas
Sho-Me Power Electric
Cooperative
SERC
3
Walter Kenyon
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
SERC
1
Todd Bennett
Associated Electric Cooperative
Inc.
SERC
3
Matt Pacobit
Associated Electric Cooperative
Inc.
SERC
5
Brian Ackermann
Associated Electric Cooperative
Inc.
SERC
6
Voter Information
Voter
Segment
Phil Hart
1
Entity
Region(s)
Associated Electric Cooperative, Inc.
Selected Answer:
Answer Comment:
AECI is in agreement with multiple commenters who have issue with this current
version.
Document Name:
Likes:
0
Dislikes:
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2 Selected Answer:
Answer Comment:
ERCOT supports the comments submitted by the IRC SRC and provides these
additional comments.
As noted above, ERCOT no longer uses the “Type 2” RAS designation, and this
reference should be removed from the footnotes and rationale boxes in this draft
standard.
R6 should be reworded to clarify compliance obligations for the RASentity. ERCOT suggests the following language:
“Each RAS
CAP to its reviewing Reliability Coordinator(s) within six full calendar months
of:...."
‐e
Additionally, the references to days and months should be standardized. There
are references to 60 calendar months, 6 calendar months, and 120 calendar
days. The SDT should consider expressing all of these time periods in the same
units—using either months or days to maintain consistency throughout the
standard.
Document Name:
Likes:
0
Dislikes:
0
Jared Shakespeare - Peak Reliability - 1 Selected Answer:
Answer Comment:
There needs to be some mechanism in place (possibly a requirement) to ensure
that RAS functionality and coordination issues are addressed in response to
physical changes to the system, e.g., removing or adding transmission or
generation Facilities. A reliability gap can be created if the physical system is
changed, but RAS are not updated or modified in response to those physical
system changes. Without a functional modification to the RAS it would not
perform according to its intended design. The five year review process cannot be
relied upon to address these scenarios, as it would result in long-term exposure
to reliability risks.
Example scenario:
{C}·
A RAS exists in an area to prevent voltage collapse
{C}·
An entity retires a generation Facility which is associated with the RAS
{C}·
Facility
The RAS is not updated to account for the retirement of the generation
{C}·
The RAS is rendered ineffective for preventing voltage collapse
{C}·
This condition is not discovered until the PC performs its 5-year review
{C}·
Until the PC performs its 5-year review, the system is vulnerable to
voltage collapse due to RAS ineffectiveness
Both R4.1.4 and Attachment 1, section III, item 4 use the same confusing
language, “a single component failure in the RAS, when the RAS is intended to
operate does not prevent the BES from meeting the same performance
requirements (defined in Reliability Standard TPL
‐001
those required for the events and conditions for which the RAS is
designed.” Though similar language is used in the currently effective set of
reliability standards, it is confusing and unclear. We recommend clarifying the
language and/or providing examples in an application guideline as part of the
standard itself that might help the reader understand the meaning of and intent
behind this language.
In R2 RC is required to follow Attachment 2 for the evaluation, what is the
required evaluation for the PC in R4? Is it Attachment 2 as well?
For R5 when a RAS operation, failure to operate, or mis-operation occurs, and a
deficiency is identified, the RAS should be removed from service until the CAP is
implemented.
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
MRO,SPP
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Consideration of Comments
Project Name: 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes | PRC‐012‐2
Comment Period Start Date: 11/25/2015
Comment Period End Date: 1/8/2016
Associated Ballots: 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC‐012‐2 AB 2 ST and 2010‐05.3 Phase 3
of Protection Systems: Remedial Action Schemes Definition IN 1 DEF
There were 46 responses, including comments from approximately 150 different people from approximately 98 different companies
representing 9 of the 10 Industry Segments as shown on the following pages.
All comments submitted can be reviewed in their original format on the project page.
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 Director of Standards, Howard
Gugel (via email) or at (404) 446‐9693.
The drafting team made the following changes to the draft standard and implementation plan based on stakeholder comments.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
1
Reliability Standard PRC-012-2
Requirements
Requirement R4
Revised the periodic evaluation time period from “at least once every 60 full calendar months” to “at least once every five full
calendar years.”
Included a provision requiring limited impact RAS be included in the periodic evaluation to ensure they still qualify for the limited
impact designation.
Requirement R6
Revised second bullet for more specificity to read: “Notifying the Reliability Coordinator of a deficiency pursuant to Requirement R5,
Part 5.2, or”.
Measures, VSLs, and Attachments
Revised to be consistent with and complement the revised requirements.
The timing of RAS operations was moved from the Implementation section to the Design section of Attachment 2 for clarity.
Rationale Boxes and Supplemental Material
Revised to complement the modified requirements and provide additional clarity.
Footnotes
Revised footnote 1 by removing the provision concerning the initial consideration of WECC Local Area Protection Scheme (LAPS) and
NPCC Type III RAS as limited impact RAS upon the effective date of PRC‐012‐2 (moved provision to Implementation Plan).
Clarifying edits made to footnote 2 regarding functional modifications.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
2
Implementation Plan
Limited Impact RAS
Included the provision (previously in footnote 1) concerning the initial consideration of WECC Local Area Protection Scheme (LAPS)
and NPCC Type III RAS as limited impact RAS upon the effective date of PRC‐012‐2.
Requirements R4 and R8
Revised language for the initial performance of obligations under Requirements R4 and R8 for consistency and clarity.
Requirement R9
Revised the Requirement R9 provision to clarify that the initial obligation for a Reliability Coordinator that does not have a RAS
database is to establish one (RAS database) by the effective date of PRC‐012‐2; i.e., during the thirty‐six (36) month implementation
period.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
3
Questions
1. Limited impact designation: Within the RAS review process of PRC‐012‐2, the drafting team included a provision that RAS can
be designated as “limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. A RAS implemented prior to the effective date of this standard that has been through the regional review process
and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When appropriate,
new or functionally modified RAS implemented after the effective date of this standard will be designated as limited impact
by the Reliability Coordinator during the RAS review process. Do you agree with the provision that RAS can be designated as
“limited impact”? If no, please provide the basis for your disagreement and an alternate proposal.
2. Implementation Plan for PRC‐012‐2: The drafting team revised the Implementation Plan to provide clarity and to lengthen the
implementation period to thirty‐six months to provide the responsible entities adequate time to establish the new working
frameworks among functional entities. Do you agree with the revised Implementation Plan? If no, please provide the basis for
your disagreement and an alternate proposal.
3. Revised Definition of “Special Protection System” and its Implementation Plan: The drafting team revised the definition of
“Special Protection System” to cross‐reference the revised definition of “Remedial Action Scheme”. The Implementation Plan
for the revised definition of “Special Protection System” aligns with the effective date of the revised definition of “Remedial
Action Scheme”. Do you agree with the proposed definition and its implementation plan? If no, please provide the basis for
your disagreement and an alternate proposal.
4. If you have any other comments that you haven’t already provided in response to the above questions, please provide them
here.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
4
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
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
5
The drafting team appreciates the feedback that stakeholders provided on the previous posting. Draft 3 of PRC‐012‐2 is a quality
results based standard that will promote reliability thanks to your participation. The drafting team revised the standard and its
implementation plan, making clarifying changes to both documents. Responses to the most prevalent comments received for each
question are located immediately below the question in this document. Responses to individual comments are not required for a
failed additional ballot in accordance with sections 4.12 and 4.13 of the Standards Process Manual. If you have a specific comment
that you would like to discuss, please contact the Standards Developer, Al McMeekin at 404‐446‐9675 or via email Al McMeekin.
Please provide your comment, your contact information, and a convenient date and time for a discussion.
1.
Limited impact designation: Within the RAS review process of PRC‐012‐2, the drafting team included a provision that RAS
can be designated as “limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations. A RAS implemented prior to the effective date of this standard that has been through
the regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact. When appropriate, new or functionally modified RAS implemented after the effective date of this standard
will be designated as limited impact by the Reliability Coordinator during the RAS review process. Do you agree with the
provision that RAS can be designated as “limited impact”? If no, please provide the basis for your disagreement and an
alternate proposal.
Limited impact designation
RAS are unique and customized assemblages of protection and control equipment that vary in complexity and impact on the
reliability of the BES. In recognition of these differences, within the structure of Requirements R1‐R4 of PRC‐012‐2, a RAS can be
proposed by the Planning Coordinator and RAS‐entity to be recognized as limited impact. The RAS‐entity may at any time, submit
Attachment 1 information to the reviewing Reliability Coordinator(s) that includes the technical justification (evaluations)
documenting that the System can meet the performance requirements (specified in Requirement R4, Parts 4.1.4 and 4.1.5)
resulting from a single RAS component malfunction or failure, respectively. The reviewing Reliability Coordinator(s) is the final
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
6
arbiter for determining whether a RAS qualifies for the limited impact designation. The limited impact designation is available to
any RAS in any Region provided the reviewing RC determines the RAS poses a low risk to BES reliability.
To achieve the limited impact designation, a RAS cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations.
The limited impact designation is modeled after the Local Area Protection Scheme (LAPS) classification in WECC (Western
Electricity Coordinating Council) and the Type 3 classification in NPCC (Northeast Power Coordinating Council). The following
information describing the aforementioned WECC and NPCC RAS is excerpted from the respective regional documentation .The
drafting team notes that the information below represents the state of the WECC and NPCC regional processes at the time of this
standard development and is subject to change before the effective date of PRC‐012‐2.
WECC: Local Area Protection Scheme (LAPS)
A Remedial Action Scheme (RAS) whose failure to operate would NOT result in any of the following:
•
•
•
Violations of TPL‐001‐WECC‐RBP System Performance RBP,
Maximum load loss ≥ 300 MW,
Maximum generation loss ≥ 1000 MW.
NPCC: Type III
An SPS whose misoperation or failure to operate results in no significant adverse impact outside the local area.
In recognition that the drafting team modeled the limited impact designation after the WECC and NPCC classifications, each RAS
implemented prior to the effective date of PRC‐012‐2 that has been through the regional review processes of WECC or NPCC and
classified as either a Local Area Protection Scheme (LAPS) in WECC or a Type 3 in NPCC, will be recognized as a limited impact RAS
upon the effective date of PRC‐012‐2 and is subject to all applicable requirements.
To propose an existing RAS (a RAS implemented prior to the effective date of PRC‐012‐2) be designated as limited impact by the
reviewing RC, the RAS‐entity must prepare and submit the appropriate Attachment 1 information that includes the technical
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
7
justification (evaluations) documenting that the System can meet the performance requirements (specified in Requirement R4,
Parts 4.1.4 and 4.1.5) resulting from a single RAS component malfunction or failure, respectively.
There is nothing that precludes a RAS‐entity from working with the reviewing RC during the implementation period of PRC‐012‐2,
in anticipation of the standard becoming enforceable. However, even if the reviewing RC determines the RAS qualifies as limited
impact, the designation is not relevant until the standard becomes effective. Until then, the existing regional processes remain in
effect as do the existing RAS classifications or lack thereof.
Additionally, the drafting team recognizes that System changes occur that could potentially alter the effect of a limited impact RAS
(increasing the reliability impact) on the BES. To address this issue, the drafting team added a provision in Requirement 4 that
explicitly requires the periodic evaluation of limited impact RAS to verify the limited impact designation remains applicable.
Requirement 4, Part 4.1.3 reads: “For limited impact RAS, the inadvertent operation of the RAS or the failure of the RAS to operate
does not cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.”
John Fontenot ‐ Bryan Texas Utilities ‐ 1
Selected Answer:
Yes
John Falsey ‐ Invenergy LLC ‐ 3 ‐ FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
8
Yes
Yes
Thomas Foltz ‐ AEP ‐ 5
Selected Answer:
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Barbara Kedrowski ‐ WEC Energy Group, Inc. ‐ 3,4,5 ‐ RFC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
9
Diana McMahon ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
Answer Comment:
The references to “limited impact” pose significant potential for
confusion and impact reliability through ambiguity as currently
documented. As written, the term “limited impact” is documented an
unofficial definition within a single standard.
Response:
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Selected Answer:
Answer Comment:
Response:
Although we agree there is a concern that the availability of the "limited
impact" definition may lead to overuse of this option.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
10
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Dave Rudolph
Basin Electric Power Cooperative
Kayleigh Wilkerson
Lincoln Electric System
Jodi Jenson
Western Area Power
Administration
Larry Heckert
Alliant Energy
Mahmood Safi
Omaha Public Utility District
Shannon Weaver
Midwest ISO Inc.
Mike Brytowski
Great River Energy
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1
MRO
1,3,5
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,6
MRO
4
MRO
1,3,5,6
MRO
2
MRO
1,3,5,6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
11
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
MRO
3,4,5,6
Tony Eddleman
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Selected Answer:
Yes
Terry BIlke ‐ Midcontinent ISO, Inc. ‐ 2
Selected Answer:
Yes
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
12
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio
n
Larry Nash
Dominion Virginia Power
SERC
Louis Slade
Dominion Resources, Inc.
SERC
Connie Lowe
Dominion Resources, Inc.
RFC
Randi Heise
Dominion Resources, Inc,
NPCC
Selected Answer:
Segme
nts
1
6
3
5
Yes
Yes
Amy Casuscelli ‐ Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
Answer Comment:
We appreciate the SDT's responsiveness to our comment in the
previous posting advocating the provision of "limited impact" RAS.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
13
Response:
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Answer Comment:
Response:
Yes
Tri‐State supports the introduction of the concept of "limited impact".
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
14
Group Name:
Group Member Name
Joseph Smith
Jeffrey Mueller
Tim Kucey
Karla Jara
Selected Answer:
Answer Comment:
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
PSEG
Entity
Regio
n
Public Service Electric and Gas
RFC
Segme
nts
1
Public Service Electric and Gas Co.
RFC
3
PSEG Fossil LLC
RFC
5
PSEG Energy Resources & Trade
LLC
RFC
6
Yes
PSEG supports the concept of a limited impact RAS designation within
PRC‐012‐2 provided that it is defined and made available to all RAS
entities.
PSEG wishes to note that the criteria for the limited impact designation
proposed in draft# 2 of PRC‐012‐2 are not consistent with the term as it
was defined in the NERC SPCS report “Special Protection Systems (SPS)
and Remedial Action Schemes (RAS): Assessment of Definition, Regional
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
15
Practices, and Application of Related Standards” dated April,
2013. Under that report, a SPS/RAS has a limited impact to the BES if
failure or inadvertent operation of the scheme does not result in any of
the following:
Non‐Consequential Load Loss ≥ 300 MW;
Aggregate resource loss (tripping or runback of generation or HVdc) >
the largest Real Power resource within the interconnection;
Loss of synchronism between two or more portions of the system each
including more than one generating plant; or
Negatively damped oscillations.
If none of the four results are projected to occur, the SPS is classified as
having a limited impact on the BES.
While PSEG agrees with the existing NPCC, ERCOT, and WECC limited
impact designations, PSEG also believes that one NERC‐wide limited
impact RAS criteria should be included in PRC‐012‐2 for new limited
impact designations. While PSEG does not advocate any specific limited
impact RAS criteria, it does note that the cited SPCS report was
approved by the NERC Planning Committee. Any RAS that meets such
criteria, whether existing or proposed, should receive limited impact
designation.
Finally, second draft of PRC‐012‐2 does not provide an affirmative
mechanism for an existing RAS to be classified as limited impact. In
order for such a review take place under R2, a RAS‐entity must initiate
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
16
the review (under R1) when: “…placing a new or functionally modified
RAS in‐service or retiring and existing RAS”. Therefore, under our
reading of the current draft of PRC‐012‐2, existing RASs which are not
undergoing functional modification do not have an opportunity to be
reviewed for a limited impact designation, and R1 should be modified to
allow such RAS entities to seek designation for existing RASs as “limited
impact.” To facilitate such analysis, PSEG’s comments in Q4 request
that the RAS entity’s Planning Coordinator have obligations under R1 to
perform the studies related to a RAS’s performance that is required in
Attachment 1.
Response:
Likes:
5
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
17
Selected Answer:
Yes
William Temple ‐ William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Greg Davis ‐ Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Yes
Answer Comment:
The Standards Drafting Team (SDT) states a RAS which is “…new or
functionally modified RAS implemented after the effective date…” can
be recognized as “limited impact.” Can a RAS currently in place and not
within the Types already “grandfathered” by this standard (e.g., Type 3
in NPCC, Type 2 in ERCOT), become recognized as “limited impact?” We
request the SDT provide more clarity on the process for determining
“limited impact” on existing RASs.
Response:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
18
Selected Answer:
John Merrell ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 1
Selected Answer:
Answer Comment:
Response:
Yes
Yes
Tacoma Power appreciates this provision.
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RFC
Group Name:
Duke Energy
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
19
Group Member Name
Doug Hils
Duke Energy
Regio
n
RFC
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Selected Answer:
Segme
nts
1
Yes
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1
Selected Answer:
Entity
Yes
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2
Group Name:
IRC Standards Review Committee
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
20
Group Member Name
Entity
Regio
n
Charles Yeung
SPP
SPP
Ben Li
IESO
NPCC
Greg Campoli
NYISO
NPCC
Mark Holman
PJM
RFC
Matt Goldberg
ISONE
NPCC
Lori Spence
MISO
MRO
Christina Bigelow
ERCOT
TRE
Ali Miremadi
CAISO
WECC
Segme
nts
2
2
2
2
2
2
2
2
Selected Answer:
Yes
Answer Comment:
The SDT states a RAS which is “…new or functionally modified RAS
implemented after the effective date…” can be recognized as “limited
impact”. Can a RAS currently in place and not within the Types already
“grandfathered” by this standard, become recognized as “limited
impact”? If so, what is the process?
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
21
Response:
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Answer Comment:
Southern Company
Entity
Regio
n
Southern Company Services, Inc.
SERC
Segme
nts
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation
and Energy Marketing
SERC
6
No
Please see response to Question #4.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
22
Response:
Yes
Steve Wenke ‐ Avista ‐ Avista Corporation ‐ 5
Selected Answer:
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
23
Yes
Chris Gowder ‐ Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Selected Answer:
Mark Kenny ‐ Eversource Energy ‐ 3
Selected Answer:
Yes
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7 ‐ NPCC
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name
Entity
Regio
n
Paul Malozewski
Hydro One.
NPCC
Segme
nts
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
24
Guy Zito
Northeast Power Coordinating
Council
NPCC
Brian Shanahan
National Grid
NPCC
NA ‐
Not
Applica
ble
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY‐ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability Council
NPCC
7
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
25
Kathleen M. Goodman
ISO‐New England
NPCC
2
Helen Lainis
NPCC
2
Michael Jones
Independent Electricity System
Operator
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Selected Answer:
Yes
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5
Selected Answer:
Yes
Rich Hydzik ‐ Rich Hydzik On Behalf of: Bryan Cox, Avista ‐ Avista Corporation, 5, 3, 1
Scott Kinney, Avista ‐ Avista Corporation, 5, 3, 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
26
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Selected Answer:
No
Answer Comment:
Texas RE does not agree with the provision that a RAS can be
designated as “limited impact”. Moreover, Texas RE recommends the
STD reconsider and treat all RASes equally, that affect the reliability of
the Bulk Electric System (BES). Texas RE is concerned the proposed
criteria for determining a “limited impact” RAS is vague and ambiguous
(e.g. “… BES Cascading, uncontrolled separation, angular instability,
voltage instability, voltage collapse, or unacceptably damped
oscillations) which may lead to the approval of a significant number of
“limited impact” RASes on the BES, posing a potential risk to
reliability. Specifically, the potential risks are that the reduced
reliability‐related considerations for the Reliability Coordinator (i.e.
Attachment 2) and the limited evaluation performed by the Planning
Coordinator (i.e. Requirement 4) pertaining to “limited impact” RASes
may lead to potential reliability gaps on the BES.
In the ERCOT region, the “Type 1” and “Type 2” designations were
removed from the regional operating guides in February 2014,
therefore, there is no longer a regional criteria for “limited” or “wide‐
area” impact as referred to in R4.1.3. As one of the goals of this project
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
27
was to eliminate the “fill‐in‐the‐blank” requirements, it seems
inappropriate to refer to regional criteria within the standard as it does
in footnotes 1, 3, 5, and 6. Texas RE requests the SDT remove that
information from the footnotes.
Response:
Yes
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Yes
Answer Comment:
Florida Power & Light appreciates the efforts of the Standard Drafting
Team in revising PRC‐012‐2, however we have concerns on the
interpretation of “limited impact” as stated in PRC‐012‐2 standard. In
many cases, RAS’s that are classified as “limited impact” may have a
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
28
larger than expected impact due to system changes. As an example,
see page 8 of the NPCC Reliability Reference Directory #7 – Special
Protection Systems. NPCC states that “it should be recognized that a
Type III SPS may, due to system changes become Type 1 or Type II”.
To ensure uniform application, we recommend the footnote in
Requirement 4 be modified as follows:
“…RAS can be designated as “limited impact” if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations for the
system conditions considered in the latest TPL‐001‐4 stability
assessment.”
Response:
Eric Olson ‐ Transmission Agency of Northern California ‐ 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
29
Selected Answer:
Mark Wilson ‐ Independent Electricity System Operator ‐ 2 ‐ NPCC
Yes
Oshani Pathirane ‐ Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1, 3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
No
Answer Comment:
While Hydro One supports the newly introduced designation of "limited
impact" RAS, we feel that its definition should instead read as shown
below, in order to ensure that future in‐serviced RAS that will be
designated by a regional review process as Type 3 (NPCC), Type 2
(ERCOT), or LAPS (WECC) will continue to be designated as having
limited impact. This is because at this early stage, it is unclear whether
the regional organizations would be modifying or terminating their RAS
review process and/or terminology as this process will newly be
conducted by the PC. For example, after the standard is approved, new
Type 3 RASs added to the NPCC system would not necessarily be
designated as being limited impact. This change in verbiage will also
minimize the need for RAS‐entities to classify RAS into the three
categories below:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
30
1) Limited impact as per NERC;
2) Non‐limited impact as per NERC;
3) NPCC Type 3 but non‐limited impact as per NERC.
"A RAS that was reviewed previously to the effective date of this
standard, or after the effective date of this standard, by a regional
process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in
WECC will be recognized as limited impact for the purposes of
Requirement 4, Parts 4.1.3 and 4.1.3."
Response:
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
No
Answer Comment:
Limited impact RAS appears to be exempt from R4.1.3 and R4.1.4. The
Rationale box for R4 defines the performance required for a “limited
impact” RAS, and then R4.1.3 and R1.4.4 define the performance
required for RAS except “limited impact” RAS. BPA believes the
performance for all RAS should be the same. Limited impact RAS should
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
31
not be singled out to be exempt from meeting the performance
requirements; it is really a matter of whether or not redundancy is
required to be able to meet the required performance.
Although BPA agrees that for a “limited impact” RAS the level of review
can be lower, we believe a “limited impact” RAS should still be designed
such that failure or inadvertent operation of the RAS does not have an
adverse impact on an adjacent TP or PC beyond the criteria the system
is planned for.
BPA’s comments also apply to Attachment 2.
Response:
Ben Engelby ‐ ACES Power Marketing ‐ 6
Group Name:
ACES Standards Collaborators ‐ PRC‐012‐2 Project
Group Member Name
Entity
Regio
n
Ellen Watkins
Sunflower Electric Power
SPP
Corporation
Segme
nts
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
32
Shari Heino
Ginger Mercier
Brazos Electric Power Cooperative, TRE
Inc.
Prairie Power, Inc.
SERC
1,3
Mark Ringhausen
Old Dominion Electric Cooperative RFC
3,4
Ryan Strom
Buckeye Power, Inc.
RFC
4
Matt Caves
SPP
1,5
Kevin Lyons
Western Farmers Electric
Cooperative
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
Central Iowa Power Cooperative
MRO
1
Mike Brytowski
Great River Energy
MRO
1,3,5,6
John Shaver
1,5
WECC 1,4,5
Selected Answer:
No
Answer Comment:
(1) The SDT needs to provide more details for “limited impact.” This is
a vague term that needs to be clarified, as “cause or contribute to BES
Cascading” could be interpreted in multiple ways. Any system that fails
to operate as designed could be a contributing cause to an
outage. How does an entity prove that a RAS does not cause
cascading? It may be impossible to prove that a RAS has limited
impact.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
33
(2) Why does the SDT give the RC the independent authority without
any specific criteria or guidelines to determine if the RAS has a limited
impact? There should be an objective set of criteria for the RC to make
a decision. We suggest adding detailed parameters or specific examples
to show how a RAS may have a limited impact. One suggestion is a local
area scheme that does not impact a larger area. The SDT could also
leverage SPP, WECC or NPCC parameters for determining limited impact
that should lead to the SDT to develop continent‐wide criteria for
determining limited impact RAS.
(3) Why does the SDT include “limited impact” RAS as being applicable
to the standard? If it has a limited impact, then it should not apply at
all. This proposal by the SDT is contrary to the past two years of NERC’s
RAI and RBR initiatives focusing on HIGH RISK activities. By definition,
“limited impact” should not matter for BES reliability. The limited
impact designation creates unnecessary compliance burdens without a
clear benefit to increased reliability of the grid.
Response:
Phil Hart ‐ Associated Electric Cooperative, Inc. ‐ 1
Group Name:
AECI
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
34
Group Member Name
Entity
Mark Ramsey
N.W. Electric Power Cooperative,
Inc.
John Stickley
N.W. Electric Power Cooperative,
Inc.
Kevin White
Northeast Missouri Electric Power
Cooperative
Skyler Wiegmann
Northeast Missouri Electric Power
Cooperative
Michael B Bax
Central Electric Power
Cooperative
Adam M Weber
Central Electric Power
Cooperative
Denise Stevens
Sho‐Me Power Electric
Cooperative
Jeff L Neas
Sho‐Me Power Electric
Cooperative
Walter Kenyon
KAMO Electric Cooperative
Theodore J Hilmes
KAMO Electric Cooperative
Phillip B Hart
Associated Electric Cooperative
Inc.
Todd Bennett
Associated Electric Cooperative
Inc.
Matt Pacobit
Associated Electric Cooperative
Inc.
Regio
n
SERC
Segme
nts
1
SERC
3
SERC
1
SERC
3
SERC
1
SERC
3
SERC
1
SERC
3
SERC
1
SERC
3
SERC
1
SERC
3
SERC
5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
35
Brian Ackermann
Selected Answer:
Associated Electric Cooperative
Inc.
SERC
6
Yes
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2
Selected Answer:
Yes
Answer Comment:
ERCOT supports the comments submitted by the IRC SRC and provides
these additional comments.
ERCOT agrees with the SDT that a “limited impact” designation should
be available. However, ERCOT no longer uses the RAS designations
“Type 1” or “Type 2,” and references to “ERCOT Type 2” in the
footnotes and rationale boxes of this draft standard should be
removed. The now defunct ERCOT “Type 2” designation was used to
identify limited impact RAS.
Today, there are existing RAS in ERCOT that, although they are no
longer designated “Type 2” still qualify as “limited impact.” ERCOT
requests clarification as to any particular process that would be
required to designate an existing RAS as “limited impact.”
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
36
Response:
Jared Shakespeare ‐ Peak Reliability ‐ 1
Selected Answer:
Yes
Answer Comment:
There are 4 WECC LAPS that exist which could, given failure to operate,
contribute to cascading or voltage instability/collapse. Peak will work
with WECC during the implementation phase to update these
designations.
Response:
Jason Smith ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ MRO,SPP
Group Name:
SPP Standards Review Group
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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37
Group Member Name
Shannon Mickens
Jason Smith
Selected Answer:
Entity
Regio
n
Southwest Power Pool
SPP
Southwest Power Pool
SPP
Segme
nts
2
2
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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38
2.
Implementation Plan for PRC‐012‐2: The drafting team revised the Implementation Plan to provide clarity and to lengthen
the implementation period to thirty‐six months to provide the responsible entities adequate time to establish the new
working frameworks among functional entities. Do you agree with the revised Implementation Plan? If no, please provide
the basis for your disagreement and an alternate proposal.
Implementation Plan for PRC‐012‐2
Because some functional entities will need to establish new frameworks, which for Reliability Coordinators could include the hiring
and training of personnel to perform and comply with the requirements of Reliability Standard PRC‐012‐2, the drafting team
asserts that the 36 month implementation period is reasonable and appropriate.
The Implementation Plan includes a provision for limited impact RAS which states: “A RAS implemented prior to the effective date
of PRC‐012‐2 that has been through the regional review processes of WECC or NPCC and is classified as either a Local Area Protection
Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited impact RAS upon the effective date of PRC‐012‐2 and is subject
to all applicable requirements. This provision was included because the drafting team modeled the limited impact designation after
those two regional classifications.
For all other RAS implemented prior to the effective date of PRC‐012‐2 for which a limited impact designation is desired, the RAS‐
entity must submit the appropriate Attachment 1 information and request the RC review the RAS for designation as limited impact.
There is nothing that precludes a RAS‐entity from preparing an Attachment 1 submission and working with the RC prior to the
effective date of PRC‐012‐2, in anticipation of the standard becoming enforceable. However, even if the reviewing RC determines
the RAS qualifies as limited impact, the designation is not relevant until the standard becomes effective. Until then, the existing
regional processes remain in effect as well as the existing RAS classifications or lack thereof.
The Implementation Plan also includes provisions that describe the initial performance of obligations under Requirements R4, R8,
and R9. These clarifying provisions were inserted based on comments from the previous posting. The aforementioned
requirements require initial actions that may be different based on the circumstances (for Requirement R4 ‐ whether the RAS is
existing, new, or functionally modified, for Requirement R8 ‐ whether or not the RAS is limited impact, for Requirement R9 ‐
whether or not an RC has an existing RAS database). The Requirement R4 language was updated to reflect the change in the
requirement from sixty (60) full calendar months to five (5) full calendar years. The Requirement R8 language was modified for
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
39
additional clarity. The Requirement R9 language was updated to clarify that a Reliability Coordinator that does not have a RAS
database must establish its database by the effective date of PRC‐012‐2; i.e. during the thirty‐six (36) month implementation
period. By implication, the second provision states that all RCs are to perform the obligation of Requirement R9 within twelve full
calendar months after the effective date of PRC‐012‐2.
Selected Answer:
Yes
John Falsey ‐ Invenergy LLC ‐ 3 ‐ FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
John Fontenot ‐ Bryan Texas Utilities ‐ 1
Yes
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
40
Thomas Foltz ‐ AEP ‐ 5 ‐
Selected Answer:
Yes
Diana McMahon ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Selected Answer:
No
Answer Comment:
As written, the implementation plan creates confusion by singling out
the 3 exceptions. SRP recommends identifying the requirements
applicable with the 36 month timeframe. Additionally, as written, there
is not established effective date for R9 where a database does not exist.
Response:
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
41
Selected Answer:
Yes
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Dave Rudolph
Basin Electric Power Cooperative
Kayleigh Wilkerson
Lincoln Electric System
Jodi Jenson
Western Area Power
Administration
Larry Heckert
Alliant Energy
Mahmood Safi
Omaha Public Utility District
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1
MRO
1,3,5
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,6
MRO
4
MRO
1,3,5,6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
42
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
MRO
3,4,5,6
Tony Eddleman
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Selected Answer:
Yes
Terry BIlke ‐ Midcontinent ISO, Inc. ‐ 2
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
43
Group Name:
Group Member Name
Larry Nash
Louis Slade
Connie Lowe
Randi Heise
Selected Answer:
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5
Dominion ‐ RCS
Entity
Regio
n
Dominion Virginia Power
SERC
Segme
nts
1
Dominion Resources, Inc.
SERC
6
Dominion Resources, Inc.
RFC
3
Dominion Resources, Inc,
NPCC
5
Yes
Amy Casuscelli ‐ Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
44
While Xcel Energy agrees with the clarifications in the Implementation
Plan, we do not believe that BES reliability is well served by substantially
increasing the revised standard’s effective date from 12 to 36
months. Recognizing that 12‐18 months is typically the minimum time
taken by a NERC Standard to progress from industry approval to
receiving FERC approval, a 36 months adder would effectively push the
standard’s effective date to 4 ‐5 years after industry approval – which
we believe is an inordinately long and unnecessary delay to realize the
BES reliability benefits promised by the proposed results‐based
standard. It is hard to conceive why the responsible entities would
need 4‐5 years “to establish the new working frameworks among
functional entities” given that the only substantial process change in the
proposed standard is due to the Reliability Coordinator serving as the
RAS review/approval entity – and the associated new working
framework is needed to support only R2 (and perhaps R3 to some
extent), which constitutes a small proportion of the standard.
Therefore, from our perspective, majority of the requirements are the
functional responsibility of a single applicable entity and do not require
establishing “new working frameworks among functional
entities”. Consequently, the previous 12 months implementation
period is reasonably adequate – particularly because all existing RAS
would retain status quo for several years beyond the standard’s
effective date due to the: (a) provision of limited impact RAS, and (b)
grandfathering of all existing approved RAS until a functional
modification occurs. We recommend reducing the implementation
period back to 12 months to realize enhanced BES reliability in a more
timely manner with the new results‐based standard.
Answer Comment:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
45
Response:
Yes
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Selected Answer:
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Selected Answer:
Yes
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
46
Group Member Name
Entity
Joseph Smith
Public Service Electric and Gas
Regio
n
RFC
Jeffrey Mueller
Public Service Electric and Gas Co.
RFC
3
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources & Trade
LLC
RFC
6
Selected Answer:
Answer Comment:
Response:
Likes:
Segme
nts
1
Yes
PSEG strongly supports the 36‐month implementation period as fair and
reasonable.
5
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
47
Yes
Yes
No
William Temple ‐ William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Selected Answer:
Answer Comment:
Daniel Mason ‐ City and County of San Francisco ‐ 5
Selected Answer:
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Selected Answer:
The SDT should accommodate the designation of “limited impact” RAS
during the implementation period of PRC‐012‐2. As stated in our
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
48
comments to Question 1 above, there needs to be a process in place to
allow the RC and RAS entity to do this.
Response:
John Merrell ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 1
Selected Answer:
Yes
Greg Davis ‐ Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Yes
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RFC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
49
Group Name:
Duke Energy
Group Member Name
Entity
Regio
n
Doug Hils
Duke Energy
RFC
Lee Schuster
Duke Energy
FRCC
Dale Goodwine
Duke Energy
SERC
Greg Cecil
Duke Energy
RFC
Selected Answer:
Segme
nts
1
3
5
6
Yes
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1
Selected Answer:
Yes
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
50
Group Name:
Group Member Name
Charles Yeung
Ben Li
Greg Campoli
Mark Holman
Matt Goldberg
Lori Spence
Christina Bigelow
Ali Miremadi
Selected Answer:
Answer Comment:
IRC Standards Review Committee
Entity
Regio
n
SPP
SPP
Segme
nts
2
IESO
NPCC
2
NYISO
NPCC
2
PJM
RFC
2
ISONE
NPCC
2
MISO
MRO
2
ERCOT
TRE
2
CAISO
WECC 2
No
The SDT should accommodate the designation of “limited impact” RAS
during the implementation period of PRC‐012‐2. As stated above, there
needs to be a process in place to allow the RC and RAS entity to do this.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
51
There should be an explicit statement in the implementation plan that
the obligation for RC approvals apply only to those new and modified
RAS after the effective date of the standard, not to those that had been
previously reviewed by the RROs under the existing standard.
Response:
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Southern Company
Group Member Name
Entity
Regio
n
Robert A. Schaffeld
Southern Company Services, Inc.
SERC
R. Scott Moore
Alabama Power Company
SERC
William D. Shultz
Southern Company Generation
SERC
John J. Ciza
Southern Company Generation
SERC
and Energy Marketing
Segme
nts
1
3
5
6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
52
Selected Answer:
Yes
Yes
Steve Wenke ‐ Avista ‐ Avista Corporation ‐ 5
Selected Answer:
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
53
Yes
Chris Gowder ‐ Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Answer Comment:
Response:
Mark Kenny ‐ Eversource Energy ‐ 3
Selected Answer:
FMPA believes 36 months is too long, and would suggest a timeframe
between 12 and 36 months.
Brent Ingebrigtson ‐ LG&E and KU Energy, LLC ‐ 1,3,5,6 ‐ SERC
Group Name:
LG&E and KU Energy, LLC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
54
Group Member Name
Brent Ingebrigtson
LG&E adn KU energy, LLC
Regio
n
SERC
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Selected Answer:
Entity
Segme
nts
1,3,5,6
Yes
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7 ‐ NPCC
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name
Entity
Regio
n
Paul Malozewski
Hydro One.
NPCC
Segme
nts
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
55
Guy Zito
Northeast Power Coordinating
Council
NPCC
Brian Shanahan
National Grid
NPCC
NA ‐
Not
Applica
ble
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY‐ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability Council
NPCC
7
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
56
Kathleen M. Goodman
ISO‐New England
NPCC
2
Helen Lainis
NPCC
2
Michael Jones
Independent Electricity System
Operator
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Selected Answer:
Yes
Answer Comment:
Revise in R8 “Requirement R8 must be completed at least once within
six (6) full calendar years of the effective date for PRC‐012‐2,” to
“Requirement R8 must be completed at least once within six (6) full
calendar years AFTER the effective date for PRC‐012‐2”. The reason for
this is that the word “of” can imply “prior to the effective date”
whereas “after” is clearly stating there is no requirement to present
evidence prior to the effective date. If the SDT agrees then R4 should
be modified as well.
Revise R9 to:
For each Reliability Coordinator that does not have a RAS database
upon the effective date of PRC‐012‐2, as described above, the initial
obligation under Requirement R9 is to establish a database on the
effective date of PRC‐012‐2 as describe above. Each RC will perform the
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
57
obligation of R9 within twelve full calendar months after the effective
date of PRC‐012‐2 as describe above.
Response:
Yes
Yes
Rich Hydzik ‐ Rich Hydzik On Behalf of: Bryan Cox, Avista ‐ Avista Corporation, 5, 3, 1
Scott Kinney, Avista ‐ Avista Corporation, 5, 3, 1
Selected Answer:
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5
Selected Answer:
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
58
Selected Answer:
No
Answer Comment:
Texas RE recommends reducing the implementation period. This is a
series of processes that already exist in some form or fashion and
should not require a new construct that would take three years. In
Requirement R9, the SDT indicates requirements follow “industry
practice” which is a twelve month periodicity. Does the SDT contend
that there are RASes in place that an RC or PC does not know about?
Texas RE recommends that the SDT eliminate the proposed
implementation period or at least shorten the proposed three‐year
implementation period for PRC‐12‐2 to six months. Alternatively, the
SDT should link the 60‐full‐calendar month compliance window in PRC‐
12‐2, R4 and the six‐ and twelve‐year compliance periods in PRC‐12‐2,
R8 to the effective date of PRC‐12‐2 and not the extended date (if any)
set forth in the proposed implementation plan.
The proposed PRC‐12‐2 establishes a process for reviewing new,
functionally modified, or retiring RAS. As the SDT has recognized, failing
to implement such a RAS review process could result in a significant gap
in reliability. Specifically, the SDT stated in the rationale for
Requirement R1 that RAS “action(s) can have a significant impact on the
reliability and integrity of the Bulk Electric System (BES).” Given the
importance of the RAS review scheme for reliability, Texas RE believes
that three years is too long to implement the process contemplated in
the proposed PRC‐12‐2.
Texas RE also believes that the nature of the review process itself also
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
59
counsels in favor of a shorter review period. For example, PRC‐12‐2, R1
– R3 establishes the basic framework for RAS review. These
requirements mandate that RAS‐entities provide certain information
regarding RAS to their respective Reliability Coordinators (RC), a
minimum four‐month period for the RC to review this information, and
then a subsequent obligation for the RAS‐entity to resolve any reliability
issues identified by the RC prior to installing, functionally modifying, or
retiring a particular RAS. Accordingly, these requirements do not
contemplate immediate changes to existing physical assets, significant
internal process transformations, or other issues that could potentially
justify a three‐year implementation period. Rather, they largely focus
solely on the exchange and review of documentation, such as one‐line
drawings, for each RAS that is likely already be in the RAS‐entity’s
possession today. RAS‐entities and their associated RCs should
therefore be able to begin the RAS review process with only minimal
lead time following the adoption of PRC‐12‐2. Texas RE would further
note that although RCs may need additional compliance resources to
perform the RAS reviews contemplated under PRC‐12‐2, the existing
language in PRC‐12‐2, R2 already provides RCs and RAS‐entities with the
flexibility to extend the review period if necessary based on a “mutually
agreed upon schedule.”
A similar rationale applies to the misoperation review and correction
process in PRC‐12‐2, R5. As the SDT notes, “[t]he correct operation of a
RAS is important for maintaining the reliability and integrity of the
BES. Any incorrect operation of a RAS indicates that the RAS
effectiveness and/or coordination has been compromised.” Texas RE
agrees with this statement. In light of this fact, however, Texas RE
believes that RAS‐entities should begin RAS operational performance
assessments following a RAS failure or misoperation immediately upon
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
60
adoption of PRC‐12‐2 in order to avoid a significant reliability gap.
If the SDT elects to retain an implementation period of any length,
Texas RE recommends that such implementation plan not apply to PRC‐
12‐2, R4 and R8. These requirements already have significant time
periods for RAS‐entities to complete their compliance obligations
embedded within them. For example, RAS‐entities have six years under
PRC‐12‐2, R8 to complete initial functional tests of their RAS (and 12
years for limited impact RAS if that definition is retained). Given that
PRC‐12‐2, R4 and R8 already provide extended compliance horizons,
Texas RE does not believe that additional time is necessary to
implement these requirements. Instead, the 6‐full‐calendar month
period in PRC‐12‐2, R4 and the six‐ and twelve‐year periods in PRC‐12‐2,
R8 should begin on the effective date of PRC‐12‐2 itself.
Additionally, the Implementation Plan contains the same “limited
impact” language Texas RE has concerns about (see response to
question 1).
Response:
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
61
Yes
Yes
Mark Wilson ‐ Independent Electricity System Operator ‐ 2 ‐ NPCC
Selected Answer:
Eric Olson ‐ Transmission Agency of Northern California ‐ 1
Selected Answer:
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
62
Oshani Pathirane ‐ Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1, 3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
Yes
Answer Comment:
Hydro One Networks Inc. would like to point out that Requirement R9
on Page 4/5 of the Implementation Plan does not stipulate a time fame
by which an RC that does not have a RAS database is required to
populate one by.
Response:
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Yes
Ben Engelby ‐ ACES Power Marketing ‐ 6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
63
Group Name:
ACES Standards Collaborators ‐ PRC‐012‐2 Project
Group Member Name
Entity
Ellen Watkins
Sunflower Electric Power
Corporation
Shari Heino
Brazos Electric Power Cooperative,
Inc.
Ginger Mercier
Prairie Power, Inc.
Mark Ringhausen
Old Dominion Electric Cooperative
Ryan Strom
Buckeye Power, Inc.
Matt Caves
Western Farmers Electric
Cooperative
John Shaver
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
Kevin Lyons
Central Iowa Power Cooperative
Mike Brytowski
Great River Energy
Regio
n
SPP
Segme
nts
1
TRE
1,5
SERC
1,3
RFC
3,4
RFC
4
SPP
1,5
WECC 1,4,5
MRO
1
MRO
1,3,5,6
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
64
Answer Comment:
Response:
We agree with the SDT that the implementation plan is appropriate.
Phil Hart ‐ Associated Electric Cooperative, Inc. ‐ 1
Group Name:
AECI
Group Member Name
Entity
Mark Ramsey
N.W. Electric Power Cooperative,
Inc.
John Stickley
N.W. Electric Power Cooperative,
Inc.
Kevin White
Northeast Missouri Electric Power
Cooperative
Skyler Wiegmann
Northeast Missouri Electric Power
Cooperative
Michael B Bax
Central Electric Power
Cooperative
Regio
n
SERC
Segme
nts
1
SERC
3
SERC
1
SERC
3
SERC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
65
Adam M Weber
SERC
Walter Kenyon
Central Electric Power
Cooperative
Sho‐Me Power Electric
Cooperative
Sho‐Me Power Electric
Cooperative
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
SERC
1
Denise Stevens
Jeff L Neas
Todd Bennett
Matt Pacobit
Brian Ackermann
Selected Answer:
3
SERC
1
SERC
3
SERC
3
SERC
5
SERC
6
Yes
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
66
Answer Comment:
ERCOT supports the comments submitted by the IRC SRC and provides
these additional comments.
The SDT should consider whether the standard should be clarified to
address the designation of “limited impact” RAS during the
implementation period of PRC‐012‐2.
Response:
Jared Shakespeare ‐ Peak Reliability ‐ 1
Selected Answer:
Answer Comment:
Response:
No
Peak will see significant additional workload burden with this standard
implementation and can plan to be ready within 18 months.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
67
Jason Smith ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ MRO,SPP
Group Name:
Group Member Name
Shannon Mickens
Jason Smith
Selected Answer:
SPP Standards Review Group
Entity
Regio
n
Southwest Power Pool
SPP
Southwest Power Pool
SPP
Segme
nts
2
2
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
68
3.
Revised Definition of SPS and its Implementation Plan: The drafting team revised the definition of Special Protection
System to cross‐reference the revised definition of Remedial Action Scheme. The Implementation Plan for the revised
definition of Special Protection System aligns with the effective date of the revised definition of Remedial Action Scheme.
Do you agree with the proposed definition and its implementation plan? If no, please provide the basis for your
disagreement and an alternate proposal.
Revised Definition of SPS and its Implementation Plan
On February 3, 2015, NERC submitted a petition to the Commission requesting approval of the revised definition of “Remedial
Action Scheme.” Along with the revised definition, NERC submitted Reliability Standards that had been revised by replacing the
term “Special Protection System” with the newly revised “Remedial Action Scheme.” On November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards. For a variety of reasons, NERC was unable to revise
every Reliability Standard that contains the term Special Protection System or its acronym SPS prior to that FERC filing. The term is
also used in various NERC, Regional Entity, and registered entity documents. Moving forward, NERC will systematically remove the
term Special Protection System and its acronym SPS from Reliability Standards during the enhanced periodic review process, and
replace the term in NERC documents as they are revised. The drafting team encourages the Regional Entities and registered
entities to expeditiously revise their documentation as well. Until the term Special Protection System can be completely erased
from NERC Reliability Standards, it is necessary to retain it in the NERC “Glossary” and cross‐reference it to the term Remedial
Action Scheme to ensure consistency of meaning regardless of which term is used. The Implementation Plan for the revised
definition of Special Protection System aligns with the effective date of the revised definition of Remedial Action Scheme.
John Fontenot ‐ Bryan Texas Utilities ‐ 1 ‐
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
69
Yes
Thomas Foltz ‐ AEP ‐ 5 ‐
Selected Answer:
Yes
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
John Falsey ‐ Invenergy LLC ‐ 3 ‐ FRCC,MRO,WECC,TRE,NPCC,SERC,SPP,RFC
Selected Answer:
Yes
Diana McMahon ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
70
Selected Answer:
Yes
Meghan Ferguson ‐ Meghan Ferguson On Behalf of: Michael Moltane, International Transmission Company
Holdings Corporation, 1
Selected Answer:
Yes
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1
MRO
1,3,5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
71
Dave Rudolph
Basin Electric Power Cooperative
MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
MRO
1,6
Larry Heckert
Western Area Power
Administration
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
MRO
3,4,5,6
Tony Eddleman
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
72
Terry BIlke ‐ Midcontinent ISO, Inc. ‐ 2
Selected Answer:
Yes
Answer Comment:
While it’s inferred from the standard, there should be an explicit
statement in the implementation plan that existing SPS implemented
under the RRO standard do not need to be re‐approved by the RC.
Response:
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio
n
Larry Nash
Dominion Virginia Power
SERC
Louis Slade
Dominion Resources, Inc.
SERC
Segme
nts
1
6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
73
Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Selected Answer:
Yes
Amy Casuscelli ‐ Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Selected Answer:
Yes
Answer Comment:
We will appreciate if the Implementation Plan can also address the
target date for retirement/elimination of the term/acronym SPS from
the NERC Glossary and Standards. Wasn’t eliminating the usage of SPS
one of the primary drivers for recommending Remedial Action Scheme
(RAS) as the preferred term when the RAS/SPS definition was revised?
Response:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
74
Selected Answer:
Yes
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Selected Answer:
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Yes
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Group Member Name
Entity
Joseph Smith
Public Service Electric and Gas
Jeffrey Mueller
Public Service Electric and Gas Co.
Regio
n
RFC
Segme
nts
1
RFC
3
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
75
Tim Kucey
PSEG Fossil LLC
RFC
5
Karla Jara
PSEG Energy Resources & Trade
LLC
RFC
6
Selected Answer:
Yes
Answer Comment:
In the future, NERC’s Reliability Standards Development Plan should
have the goal of eliminating “Special Protection System” or “SPS” from
standards when those standards are revised.
Response:
Likes:
5
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
76
Selected Answer:
Yes
Yes
Greg Davis ‐ Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Selected Answer:
Yes
William Temple ‐ William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Selected Answer:
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
John Merrell ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
77
Selected Answer:
Yes
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RFC
Group Name:
Group Member Name
Doug Hils
Lee Schuster
Dale Goodwine
Greg Cecil
Selected Answer:
Duke Energy
Entity
Regio
n
Duke Energy
RFC
Segme
nts
1
Duke Energy
FRCC
3
Duke Energy
SERC
5
Duke Energy
RFC
6
Yes
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
78
Selected Answer:
Yes
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2
Group Name:
IRC Standards Review Committee
Group Member Name
Entity
Regio
n
Charles Yeung
SPP
SPP
Ben Li
IESO
NPCC
Greg Campoli
NYISO
NPCC
Mark Holman
PJM
RFC
Matt Goldberg
ISONE
NPCC
Lori Spence
MISO
MRO
Christina Bigelow
ERCOT
TRE
Ali Miremadi
CAISO
WECC
Segme
nts
2
2
2
2
2
2
2
2
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
79
Selected Answer:
Yes
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Group Member Name
Robert A. Schaffeld
R. Scott Moore
William D. Shultz
John J. Ciza
Selected Answer:
Southern Company
Entity
Regio
n
Southern Company Services, Inc.
SERC
Segme
nts
1
Alabama Power Company
SERC
3
Southern Company Generation
SERC
5
Southern Company Generation
and Energy Marketing
SERC
6
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
80
Selected Answer:
Yes
Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 ‐ NPCC
Selected Answer:
Yes
Steve Wenke ‐ Avista ‐ Avista Corporation ‐ 5
Selected Answer:
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Yes
Mark Kenny ‐ Eversource Energy ‐ 3
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
81
Selected Answer:
Yes
Chris Gowder ‐ Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Selected Answer:
Yes
Brent Ingebrigtson ‐ LG&E and KU Energy, LLC ‐ 1,3,5,6 ‐ SERC
Group Name:
LG&E and KU Energy, LLC
Group Member Name
Entity
Regio
n
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
justin Bencomo
LG&E and KU Energy, LLC
SERC
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
Linn Oelker
LG&E and KU Energy, LLC
SERC
Segme
nts
1,3,5,6
1,3,5,6
3
6
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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82
Dan Wilson
Selected Answer:
LG&E and KU Energy, LLC
SERC
Yes
Segme
nts
1
Brian Shanahan
National Grid
NPCC
NA ‐
Not
Applica
ble
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7 ‐ NPCC
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name
Entity
Regio
n
Paul Malozewski
Hydro One.
NPCC
Guy Zito
Northeast Power Coordinating
NPCC
Council
5
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
83
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY‐ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability Council
NPCC
7
Kathleen M. Goodman
ISO‐New England
NPCC
2
Helen Lainis
NPCC
2
Michael Jones
Independent Electricity System
Operator
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
84
Selected Answer:
Yes
Yes
Yes
Rich Hydzik ‐ Rich Hydzik On Behalf of: Bryan Cox, Avista ‐ Avista Corporation, 5, 3, 1
Scott Kinney, Avista ‐ Avista Corporation, 5, 3, 1
Selected Answer:
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5
Selected Answer:
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Selected Answer:
Yes
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
85
Yes
Eric Olson ‐ Transmission Agency of Northern California ‐ 1
Selected Answer:
Yes
Jennifer Losacco ‐ NextEra Energy ‐ Florida Power and Light Co. ‐ 1 ‐ FRCC
Selected Answer:
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Selected Answer:
Yes
Mark Wilson ‐ Independent Electricity System Operator ‐ 2 ‐ NPCC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
86
Selected Answer:
Yes
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Selected Answer:
Oshani Pathirane ‐ Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1, 3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Selected Answer:
Yes
Yes
Ben Engelby ‐ ACES Power Marketing ‐ 6
Group Name:
ACES Standards Collaborators ‐ PRC‐012‐2 Project
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
February 3, 2016
87
Group Member Name
Entity
Ellen Watkins
Sunflower Electric Power
Corporation
Shari Heino
Brazos Electric Power Cooperative,
Inc.
Ginger Mercier
Prairie Power, Inc.
Mark Ringhausen
Old Dominion Electric Cooperative
Ryan Strom
Buckeye Power, Inc.
Matt Caves
Western Farmers Electric
Cooperative
John Shaver
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
Kevin Lyons
Central Iowa Power Cooperative
Mike Brytowski
Great River Energy
Regio
n
SPP
Segme
nts
1
TRE
1,5
SERC
1,3
RFC
3,4
RFC
4
SPP
1,5
WECC 1,4,5
MRO
1
MRO
1,3,5,6
Selected Answer:
No
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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88
Answer Comment:
The SDT should eliminate the SPS definition in its entirety. An archived
definition could also reference the current definition by stating “see
Remedial Action Scheme.” There is no reason to keep SPS as an active
glossary term. This will only cause more confusion in the industry.
Response:
Phil Hart ‐ Associated Electric Cooperative, Inc. ‐ 1
Group Name:
AECI
Group Member Name
Entity
Mark Ramsey
N.W. Electric Power Cooperative,
Inc.
John Stickley
N.W. Electric Power Cooperative,
Inc.
Kevin White
Northeast Missouri Electric Power
Cooperative
Skyler Wiegmann
Northeast Missouri Electric Power
Cooperative
Michael B Bax
Central Electric Power
Cooperative
Regio
n
SERC
Segme
nts
1
SERC
3
SERC
1
SERC
3
SERC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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89
Adam M Weber
SERC
Walter Kenyon
Central Electric Power
Cooperative
Sho‐Me Power Electric
Cooperative
Sho‐Me Power Electric
Cooperative
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
SERC
1
Denise Stevens
Jeff L Neas
Todd Bennett
Matt Pacobit
Brian Ackermann
Selected Answer:
3
SERC
1
SERC
3
SERC
3
SERC
5
SERC
6
Yes
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2
Selected Answer:
Yes
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90
Jared Shakespeare ‐ Peak Reliability ‐ 1 ‐
Selected Answer:
Yes
Jason Smith ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ MRO,SPP
Group Name:
Group Member Name
Shannon Mickens
Jason Smith
Selected Answer:
SPP Standards Review Group
Entity
Regio
n
Southwest Power Pool
SPP
Southwest Power Pool
SPP
Segme
nts
2
2
Yes
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4.
If you have any other comments that you haven’t already provided in response to the above questions, please provide
them here.
Stakeholders commented on a variety of topics and asked for clarity in some areas. The drafting team made numerous additions
to the rationales and Supplemental Material in the draft standard to address the clarity concerns. The information contained in
the rationale boxes is appended to the end of the standard after approval and as such remains part of the standard for perpetuity.
The drafting team’s position on the various topics are stated below. For comments concerning the limited impact designation or
the implementation plan, please reference questions 1 and 2 above.
General
The drafting team is charged with assigning the requirements of the new standard to the specific users, owners, and operators of
the Bulk‐Power System while incorporating the reliability objectives of all the RAS‐related standards. In drafting this standard, the
team has worked diligently to minimize the changes that will be required from the existing processes.
Each requirement of the standard has a reliability objective. It is the intent of the drafting team to be as non‐prescriptive as
possible to allow entities latitude in developing procedures and practices to satisfy the “how” of those requirements. The standard
provides a skeletal system on which the applicable entities can build and codify their processes.
RAS Review
Because each Remedial Action Scheme (RAS) is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES), the drafting team maintains a review of each proposed new RAS, or each existing RAS proposed
for functional modification or retirement should be performed. The owner(s) of the RAS are responsible for the comprehensive
design and detailed implementation of the RAS. The drafting team uses the term RAS‐entity and defines it in the Applicability of
PRC‐012‐2 as the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. Because the RAS‐
entity is the party that designs and implements its RAS, the drafting team maintains an independent review of the RAS, as is
currently performed by technical groups from the Regions, is necessary. To promote a comprehensive review of the RAS, the RAS‐
entity must provide the reviewer information (Attachment 1) that details the RAS design, function, and operation.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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Reliability Coordinator
The drafting team maintains that the Reliability Coordinator (RC) that coordinates the area where the RAS is located is the best‐
suited functional entity to perform the Remedial Action Scheme (RAS) review because the RC has the widest‐area reliability
perspective of all functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide Area purview better
facilitates the evaluation of interactions among separate RAS, as well as interactions among RAS and other protection and control
systems. The selection of the RC also minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator, Transmission Planner, or other entities involved in the planning or
implementation of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain objective
independence.
The drafting team does not, by virtue of assigning the RAS review to the RC, expect the RC to possess more information or ability
than anticipated by their functional registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not have compliance requirements. The drafting team is not precluded
from developing Reliability Standards that address functions not described in the model. Reliability Standard requirements take
precedence over the Functional Model. For reference, please see the Introduction section of NERC’s Reliability Functional Model,
Version 5, November, 2009.
The RC has the “flexibility” to request information or assistance from relevant entities (third parties) to participate in the review if
the RC believes it will enhance the quality and efficiency of the review process; however, the RC will retain the responsibility for
compliance. The drafting team maintains that RCs have options for accomplishing their review responsibilities ‐some RCs may
choose to hire additional staff while others may enter into business arrangements with third parties. The drafting team included a
thirty‐six (36) month implementation period for PRC‐012‐2 to provide sufficient time for the RCs and other applicable entities to
develop the framework of their choosing.
Planning Coordinator
In RAS‐review: The Planning Coordinator (PC) or Transmission Planner (TP) is the entity that performs the planning studies and
most often identifies the need for a RAS and/or determines the necessary RAS characteristics. These studies are included in the
Attachment 1 information supplied by the RAS‐entity to the Reliability Coordinator (RC) for RAS review and approval. Because the
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94
PC is involved in developing the studies and/or evaluations, the drafting team did not include them as mandatory participants in
the RAS review and approval process where they would be responsible for judging and approving their own work.
In Requirement R4: Because they have a wide area planning perspective, the PC is the best‐suited functional entity to perform the
periodic RAS evaluation to verify the continued effectiveness and coordination of the RAS, its inadvertent operation performance,
and the performance for a single component failure. The items that must be addressed in the evaluations include: 1) RAS
mitigation of the System condition(s) or event(s) for which it was designed; 2) RAS avoidance of adverse interactions with other
RAS and with protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a single component
failure. The evaluation of these items involves modeling and studying the interconnected transmission system, similar to the
planning analyses performed by PCs. To promote reliability, the PC is required to provide the results of the evaluation to each
impacted TP and PC, in addition to each reviewing RC and RAS‐entity. In cases where a RAS crosses PC boundaries, each affected
PC is responsible for conducting either individual evaluations or participating in a coordinated evaluation.
RAS‐entity
The term RAS‐entity is defined in the Applicability as the Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) has a single owner, then that RAS‐entity has sole responsibility for all
the activities assigned within the standard to the RAS‐entity.
The standard does not stipulate compliance methods. RAS‐entities have the option of collaborating to fulfill their responsibilities
for each applicable requirement. Such collaboration and coordination should promote efficiency in achieving the reliability
objectives of the requirements; however, the individual RAS‐entity must be able to demonstrate its participation for compliance.
As an example, the individual RAS‐entities could collaborate to produce and submit a single, coordinated Attachment 1
(acknowledging all RAS‐entities that participated in the provision of data) to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Participate (used in Requirements R5, R6, R8)
The drafting team is charged with assigning the requirements of the new standard to the specific users, owners, and operators of
the Bulk‐Power System while incorporating the reliability objectives of all the RAS‐related standards. In drafting this standard, the
drafting team has worked diligently to minimize the changes that will be required from the existing processes. The drafting team
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recognizes that RAS with multiple owners inherently require coordination among all the participating RAS‐entities from the first
conceptual design through construction to operations, testing, maintenance and retirement.
For purposes of PRC‐012‐2, when a RAS has more than one owner, each RAS‐entity is obligated to participate in the various
activities identified by the requirements to the extent of its ownership. Collaboration, coordination, and communication between
and among entities regarding RAS issues helps to ensure efforts are not duplicated and best serves reliability by promoting
awareness. For purposes of creating efficiencies, the drafting team maintains registered entities that currently share ownership of
a RAS (RAS‐entities) are in some manner already communicating, sharing information, and coordinating RAS tasks such as
operations analysis, Corrective Action Plan (CAP) development, and functional testing. The drafting team is confident that entities
will continue to do this after this standard is effective and that entities will communicate with each other if there is any question
or doubt of responsibility surrounding any requirement.
From the NERC Drafting Team Reference Manual, Version 2, January 2014, Attachment A — Verbs Used in Reliability Standards:
“When developing a new or revised standard, DTs should try to use terms that have already been defined or terms that are
already used in other Reliability Standards to achieve a high degree of consistency between standards. To that end, the Standards
staff, working with key DT members, put together the following list of verbs and their associated definitions. These verbs are all
used in requirements in existing Reliability Standards. This verb list and its definitions are not in the Glossary of Terms used in
NERC Reliability Standards but these verbs and their definitions should serve as a reference for DTs who are trying to minimize the
introduction of new terms into Reliability Standards. Participate is defined as “To take part or share in something.”
Requirement R8 – functional testing
The reliability objective of Requirement R8 is to maintain the non‐Protection System components of a RAS; i.e., the controllers
(programmable logic controllers (PLCs), personal computers (PCs), multi‐function programmable relays, remote terminal units
(RTUs), and logic processors), and to verify the overall performance of the RAS through functional testing. Functional tests validate
RAS operation by ensuring System states are detected and processed, and that actions taken by the controls are correct and occur
within the expected time using the in‐service settings and logic (functional testing by default operates the processing logic and
infrastructure of a RAS). Functional testing should not be confused with the component focused maintenance of PRC‐005
Protection System Maintenance. PRC‐005 is not applicable to non‐Protection System components such as RAS controllers.
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RAS designated as limited impact have functional testing intervals of up to twelve full calendar years. However, all other RAS have
up to six full calendar year intervals because of the higher risk they pose to negatively impact BES reliability should they operate
incorrectly or fail to operate. The drafting team recognizes that PRC‐005 extends the maintenance interval for monitored multi‐
function programmable relays to twelve calendar years; however, the drafting team asserts that the inadvertent operation or
failure of a RAS subject to the six year functional test interval poses too much risk to the reliability of the BES to extend the test
interval beyond six years.
Answer Comment:
John Fontenot ‐ Bryan Texas Utilities ‐ 1
na
Barbara Kedrowski ‐ WEC Energy Group, Inc. ‐ 3,4,5 ‐ RFC
Answer Comment:
We maintain our previous position that the draft standard is entirely
deficient due to the patchwork nature of responsibility for a RAS,
especially when there are multiple Owners of portions of the RAS. The
standard appears it would be effective where there is only one RAS
entity. However, there is no mechanism for overall coordination and
responsibility for the case when there are multiple owners. In this
respect, the previous draft was superior in that it recognized there
needs to be a single RAS Owner that has overall responsibility for
ensuring the requirements of PRC‐012‐2 are met. There is no entity
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designated to take the lead in developing the data needed for R1,
including the technical studies needed to describe system
performance. A weak acknowledgement of the need for collaboration
among multiple entities is a statement in the R5 Rationale: “RAS‐
entities may need to collaborate with their associated Transmission
Planner to comprehensively analyze RAS operational
performance.” There is nothing in the Standard as written that will
drive the needed “directed collaboration” to bring beneficial results in
the analysis of RAS operations and any corrections needed.
Our recommendation is to restore the RAS‐Owner entity (or RAS‐
Coordinator ?) and to identify this entity as the Transmission Owner
and/or Transmission Planner having primary interest and technical
capability to execute the technical studies (steady state, dynamic, etc),
and designate these to have lead or primary responsibility for the
Requirements. The individual RAS‐entities with ownership of related
equipment would be responsible to participate in the requirements as
listed, under the umbrella of the primary entity.
Absent a Standard requiring a single entity to take charge of the
development of RAS, analysis of its operations, and development of
needed CAP’s, it appears unlikely that the Standard will actually
produce meaningful results, nor an improvement in reliability. This
despite the great amount of effort that will be required to ensure
compliance.
Response:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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Likes:
1
Associated Electric Cooperative, Inc., 1, Hart Phil
Dislikes:
0
Gul Khan ‐ Gul Khan On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Answer Comment:
In regards to R8 Oncor Electric Delivery does not differentiate between
functional testing of a protection system and functional testing of a
RAS. This is an unnecessary requirement, and any responsible entity will
perform functional testing of a RAS when maintaining the protection
system components of a RAS. Oncor recommends that an entity whose
PRC‐005‐2 maintenance program covers functional testing of its RASs
does not have to comply with PRC‐012‐2 R8. The non protection system
components of a RAS are tested when performing maintenance under
PRC‐005. Hence adhering to the proposed R8 in PRC‐012‐2 will only
require additional documentation while not positively affecting the
reliability of the BES.
In regards to R1 Oncor Electric Delivery believes the RAS information
required in attachment 1 contains more than is necessary for a review
and cannot always be obtained for every RAS. Also providing all this
information is not required prior to placing a protection system under
PRC‐005 in service so it should also not be required under PRC‐012‐2.
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Response:
Diana McMahon ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer Comment:
SRP appreciates the opportunity to comment on the proposed revisions
to PRC‐012 and provides the following additional comments related tot
he draft posted.
1) Similar to concerns with “limited impact”, “functionally modified” as
written is an unofficial defined term within the standard. SRP
recommends defining the term “functionally modified” and including it
within the NERC Glossary of Terms.
2) Attachment 1 and 2 as originally presented were checklists. As
currently written, they are not. Rather they are itemized lists of
information to be included or assessment to be made. As written the
Attachments 1 & 2 create ambiguity in regards to what is expected from
the submitter and reviewer.
3) Under R1, the identification within the rationale that “ideally, when
there is more than one RAS‐ entity for a RAS…” is not captured within
the language of the standard. SRP agrees with this intention, however
recognizes that once the rationale is removed from the standard, this
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will be lost. SRP recommends adjusting the language of the standard or
including the language within the measure to more clearly indicate the
intention of the SDT.
4) Under R3, the RAS entity that receives feedback is required to
“resolve each issue to obtain approval”. This language as written does
not specify a resubmittal of the information required under Attachment
1 and fails to reactivate the timeframe identified for the reviewer under
R3. SRP recommends adjusting the language to “ resolve each issue and
resubmit Attachment 1 information to the reviewing RC to obtain
approval…”.
5) Under R4, there is an inconsistent use of quotes around “limited
impact” again pointing to the previously discussed confusion created by
imbedding an unofficially defined term within the standard.
6) R^ has a singular/ plural inconsistency "Pursuant to the Requirements
R5, or..". This should be singular.
Similar to the issue identified under R1, R8 requires each entity to
participate in “performing” the functional test. This would require all
partial owners to be involved in the functional test of a RAS.
Participation is vague and can result in confusion over what would
constitute participation. SRP recommends adjusting the language to
read “the RAS entity shall perform a functional test..”. This would allow
joint owners to coordinate the activities
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Response:
Emily Rousseau ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO
Group Name:
MRO‐NERC Standards Review Forum (NSRF)
Group Member Name
Entity
Joe Depoorter
Madison Gas & Electric
Chuck Lawrence
American Transmission Company
Chuck Wicklund
Otter Tail Power Company
Dave Rudolph
Basin Electric Power Cooperative
Kayleigh Wilkerson
Lincoln Electric System
Jodi Jenson
Western Area Power
Administration
Larry Heckert
Alliant Energy
Mahmood Safi
Omaha Public Utility District
Shannon Weaver
Midwest ISO Inc.
Regio
n
MRO
Segme
nts
3,4,5,6
MRO
1
MRO
1,3,5
MRO
1,3,5,6
MRO
1,3,5,6
MRO
1,6
MRO
4
MRO
1,3,5,6
MRO
2
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Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
MRO
3,4,5,6
Tony Eddleman
Wisconsin Public Service
Corporation
Nebraska Public Power District
MRO
1,3,5
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Answer Comment:
R4.1.3 and R4.1.4 – These requirements refer to ‘single component
malfunction’ and ‘single component failure’ respectively. However, the
standard does not contain any identification or clarification of which
types of components must be included and which may be excluded in
RAS evaluations. This deficiency could be addressed by including text in
the Supplemental Material section under Requirement 4 that the
drafting team developed for a response in its Consideration of
Comments for Draft 1 of PRC‐012‐2.
• “An exhaustive list of components is not practical given the variety
that could be applied in RAS design and implementation. See Item 4a in
the Implementation Section of Attachment 1 in the Supplemental
Material section for typical RAS components for which redundancy may
be considered. The RAS‐entity should have a clear understanding of
what components were applied to put a RAS into service and which
were already present in the system before a RAS was installed. The RC
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will make the final determination regarding which components should
be regarded as RAS components during its review”.
R5 – This requirement does not obligate RAS‐entities to provide their
results of the operational performance analysis of a RAS event to
impacted Transmission Planners and Planning Coordinators. However,
this action should be proposed in the Supplemental Material section.
R6 – This requirement does not obligate RAS‐entities to provide their
Corrective Action Plans to impacted Transmission Planners and Planning
Coordinators. However, this action should be proposed in the
Supplemental Material section.
R8 ‐ The purpose of Version 2 of PRC‐005 was to consolidate all
maintenance and testing of relays under one Standard. Having RAS
testing within PRC‐012‐2 would be contrary to that end. The NSRF
proposes to address this concern as follows:
• Functional testing of RAS (as stated in Requirement 8 of PRC‐012‐2)
is a maintenance and testing activity that would be better included in
the PRC‐005 standard. The present PRC‐005‐2 Reliability Standard is the
maintenance standard that replaces PRC‐005‐1, 008, 011 and 017 and
was designed to cover the maintenance of SPSs/RASs. However,
Reliability Standard PRC‐005‐2 lacks intervals and activities related to
non‐protective devices such as programmable logic controllers. The
NSRF recommends that a requirement for maintenance and testing of
non‐protective RAS components be added to a revision of PRC‐005‐6,
rather than be an outlying maintenance requirement located in the
PRC‐012‐2 Standard.
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R8. Of the proposed Standard states: Each RAS‐entity shall participate in
performing a functional test of each of its RAS to verify the overall RAS
performance and the proper operation of non‐Protection System
components. Please provide clarification that the word test and verify
is aligned with the definitions contained in the Supplementary
Reference and FAQ, PRC‐005‐2 Protection System Maintenance dated
October 2012.
Response:
Maryclaire Yatsko ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5,6 ‐ FRCC
Answer Comment:
a. The Standard Drafting Team gave examples of “functional
modifications” in the Rationale Box for R1. Seminole requests that
these examples be moved into the Standard language to make these
examples more than mere suggestions by the SDT, which would be the
case if this language is left in the Application Guidelines.
b. For Requirement R1, can the SDT confirm that each RAS‐entity, even
if the entity is only a partial ower of a RAS, must submit a fully
completed Attachment 1 submission?
c. For Requirement R3, if the RAS‐entity disagrees with "issues" the RC
indicates, can the RAS‐entity document technical reasons why the RAS‐
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entity's design is satisfactory or does the RAS‐entity have to get REC
approval?
d. Footnote 1 for Requirement 4 appears to state that the only existing
limited impact RAS are located in NPCC, ERCOT, and WECC. The
footnote does not appear to allow for existing limited impact RAS in
other Regions, specifically the FRCC. Seminole requests that the
drafting team modify the language in the Standard and footnote to
clarify that existing RAS in the FRCC and other Regions can also have
existing limited impact RAS.
Response:
Randi Heise ‐ Dominion ‐ Dominion Resources, Inc. ‐ 5
Group Name:
Dominion ‐ RCS
Group Member Name
Entity
Regio
n
Larry Nash
Dominion Virginia Power
SERC
Louis Slade
Dominion Resources, Inc.
SERC
Segme
nts
1
6
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Connie Lowe
Dominion Resources, Inc.
RFC
3
Randi Heise
Dominion Resources, Inc,
NPCC
5
Answer Comment:
Dominion believes that the term “in‐kind” included in Footnote
4, “Changes to RAS hardware beyond in‐kind replacement of existing
components” is vague and suggests that the term be clarified such that
the reader knows that the replacement of an electromechanical relay
with a microprocessor relay is construed as an “in kind” replacement, as
the drafting team noted in their December 15th presentation. The
concept of “In‐kind” replacement could be taken a step further. For
example, a discrete ladder logic circuit that includes contacts,
overcurrent and voltage relays could be replaced entirely inside the
software logic of a multifunction device. From a black‐box viewpoint,
the old and new RAS would be identical in function. Dominion also
suggests for additional consideration that the replacement of many
discrete components with a single multifunction component also be
considered an “in kind” replacement so long as for a given set of inputs
the “black box” produces the same outputs as the previous RAS would.
In the case of a breaker failure event, the Standards Drafting Team
“SDT” indicates the need for RAS redundancy even though that would
be a double failure event (failure of the RAS and failure of the
breaker). Dominion suggests that it is sufficiently redundant to use the
existing breaker failure relay (non‐redundant) to initiate both RAS
schemes. This can be accomplished by each RAS using a different
contact off the breaker failure relay that was separately fused.
Dominion suggests the SDT consider using a consistent measure of
time, either calendar months or full calendar days, for responding and
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reporting. For example, Requirement 2 states: Each Reliability
Coordinator that receives Attachment 1 information pursuant to
Requirement R1, shall, within four‐ full‐ calendar months of receipt, or
on a mutually agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written feedback to each
RAS‐entity.” Whereas Requirement 4 states that: “Each RAS entity,
within 120‐ full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with
its reviewing Reliability Coordinator(s), shall:”
Response:
Amy Casuscelli ‐ Amy Casuscelli On Behalf of: Peter Colussy, Xcel Energy, Inc. , 6
Answer Comment:
We agree with the footnote definition of “limited impact” RAS and the
exceptions stated in parts 4.1.3 and 4.1.6 of R4.
Usage of both RAS‐owner and RAS‐entity in the previous posting of the
draft standard was confusing – so we agree with the SDT’s solution to
eliminate one of them. We also agree that retaining the previous
definition of RAS‐owner as Applicable Entity is more
appropriate. However, we do not understand what is the compelling
need and/or the benefit of reassigning the RAS‐owner definition to the
RAS‐entity. Absent a rationale by the SDT for preferring RAS‐entity, we
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108
suggest using RAS‐owner since it better aligns with the various owners
comprised in the definition.
Response:
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer Comment:
Regarding the third bullet when describing Functional
modifications; what does "in‐kind" mean? The description in the
Supplemental Material describes it but Tri‐State believes the phrase
"preserves the original functionality" is more appropriate. This is used
in several places (Rationale for R1, Att. 1, and Att. 2, at a minimum).
Regarding the fourth bullet when describing Functional modifications;
we suggest changing the language to read "...beyond correcting existing
errors". The phrase "error correcting" has other implications and is not
described in the Supplemental Material.
Tri‐State would like to know what the SDT's intentions were when
adding the statement "The RC is not expected to possess more
information or ability than anticipated by their functional registration as
designated by NERC" to the Rationale for Requirement R2. We don't
know why that was necessary.
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Response:
John Seelke ‐ PSEG ‐ 1,3,5,6 ‐ NPCC,RFC
Group Name:
PSEG
Group Member Name
Joseph Smith
Jeffrey Mueller
Tim Kucey
Karla Jara
Answer Comment:
Entity
Regio
n
Public Service Electric and Gas
RFC
Segme
nts
1
Public Service Electric and Gas Co.
RFC
3
PSEG Fossil LLC
RFC
5
PSEG Energy Resources & Trade
LLC
RFC
6
1. Suppose a RAS is intended to cause a generator to run‐back under a
defined set of conditions. Further, suppose that the generator and the
RAS‐entity that sends run‐back signals to the generator’s DCS are
different (non‐affiliated) companies. Is the generator’s DCS a part of the
RAS?
2. R4.2 should be expanded with respect to the entities a Planning
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Coordinator “provides the results of the RAS evaluation including any
identified deficiencies.” PSEG believes that the results should also be
provided to non‐RAS entities (i.e., TOs, GOs, and DPs) whose facilities
are impacted by the operation of a RAS.
Attachment 1 and R1 should be modified as follows for the reasons
provided:
3. In many cases, a single RAS has multiple RAS entities. Attachment 1
should be modified so that each RAS entity’s components in the RAS are
clearly identified.
4. The entity responsible for providing the information required in
Attachment 1 Section II should be identified. For example, item II.6 and
III.4 should be completed by the Planning Coordinator (who has the
capability to provide that information) rather than the RAS entity. The
comments that PSEG submitted for the initial draft addressed this
concern and recommended that the RAS entity’s Transmission Planner
prepare this section; however, since the standard is applicable to
“Planning Coordinator,” that entity is more appropriate. In response to
PSEG’s comments, the SDT stated:
“The drafting team acknowledges that the need for a RAS and/or the
determination of RAS characteristics are most often identified through
planning studies performed by the Planning Coordinators or
Transmission Planners. These studies are included in the Attachment 1
information supplied to the Reliability Coordinator (RC) for the RAS
review and approval.”
PSEG unequivocally agrees with this comment. Therefore, R1 should be
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modified to state that “each RAS entity and its Planning Coordinator
shall provide the information required of it in Attachment 1 ….”
With this change, Attachment 1 should be modified to identify which
entity (RAS entity or Planning Coordinator) is required to provide what
information.
Other Attachment 1 items:
5. Items II.1 and II.2 are duplicative to I.4.e and I.4.f. Therefore, items
I.4.e and I.4.f should be deleted. Also, Items II.1 (contingencies and
System conditions) and II.2 (RAS action) should be stated so that each
contingency and System condition is linked to an expected RAS action
(assuming all RAS equipment operates properly). As a simplification,
the two items could be combined in to one item: “Each contingency and
System condition that the RAS is intended to remedy and the associated
RAS response.”
6. Item III.1 should have include be expanded to say “and
documentation showing that any multifunction device used to perform
RAS function(s), in addition to other functions such as protective
relaying or SCADA, does not compromise the reliability of the RAS when
the device is not in‐service or is being maintained.” This is required to
ensure that non‐RAS equipment that is essential to the successful
operation of the RAS is not inadvertently removed from service.
Response:
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Likes:
5
PSEG ‐ PSEG Energy Resources and Trade LLC, 6, Jara Karla
PSEG ‐ PSEG Fossil LLC, 5, Kucey Tim
Long Island Power Authority, 1, Ganley Robert
PSEG ‐ Public Service Electric and Gas Co., 1, Smith Joseph
PSEG ‐ Public Service Electric and Gas Co., 3, Mueller Jeffrey
Dislikes:
0
John Pearson ‐ John Pearson On Behalf of: Michael Puscas, ISO New England, Inc., 2
Answer Comment:
Under Requirement R4.2 additional clarification regarding the as to the
“reviewing Reliability Coordinator”. We suggest changing the wording
to the “impacted” Reliability Coordinator from “reviewing” as shown
below.
4.2. Provide the results of the RAS evaluation including any identified
deficiencies to
each impacted Reliability Coordinator and RAS‐entity, and each
impacted
Transmission Planner and Planning Coordinator.
Under R5, each RAS entity must review any RAS operation whether the
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operation was as designed or a there was an unintended or adverse BES
response. Under R6, wording calls for a Corrective Action Plan (CAP) to
be developed no matter what. We suggest clarifying wording under R6
as follows to limit development of a CAP to when RAS operation caused
an unintended or adverse BES response.
R6. Each RAS‐entity shall participate in developing a Corrective Action
Plan (CAP) when RAS operation caused an unintended or adverse BES
response and submit the CAP to its impacted Reliability Coordinator(s)
within six full calendar months…
Response:
Daniel Mason ‐ City and County of San Francisco ‐ 5
Answer Comment:
Hetch Hetchy does not agree with the proposed change in the definition
of a RAS entity. HHWP believes that the definition of a RAS entity in the
last posted version of PRC‐012 should be retained and that the RAS
owner designated to represent all RAS‐owners should be responsible
for ensuring information provided for evaluation of RAS impacts is
available to the appropriate reliability entities .The proposed change in
the definition of a RAS entitiy unnecessarily expands the scope of
entities involved in RAS evaluation and is likely to lead to duplication of
efforts, or reliabilty gaps. Having a single point of contact for RAS
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coordination/management is the efficient and effective approach for
ensuring that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric
System.
Response:
William Temple ‐ William Temple On Behalf of: Mark Holman, PJM Interconnection, L.L.C., 2
Answer Comment:
The Rationale Box for Req. 1 contains important guidelines for when a
review of RAS is needed. These should be captured and retained in a
standing Guideline. Also, there should be a need to review a RAS when
the settings that initiate the RAS are changed.
In the Applicability section of Attachment 3, the three entities identified
for obligations to PRC‐012‐2 are explained with a concluding caveat that
these entities can collaborate to meet the requirements of the
standard.
“The standard does not stipulate particular compliance methods. RAS‐
entities have the option of collaborating to fulfill their responsibilities
for each applicable requirement. Such collaboration and coordination
may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS‐entity must be able to
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demonstrate its participation for compliance. As an example, the
individual RAS‐entities could collaborate to produce and submit a
single, coordinated Attachment 1 to the reviewing RC pursuant to
Requirement R1 to initiate the RAS review material to the process.”
We request how this allowance will be included in the RSAW for this
standard?
With regards to Req. 4.2, we suggest that the Planning Coordinator only
needs to provide evidence of the evaluation results to the RAS‐entity if
a deficiency is identified. This will help reduce the compliance burden
of submitting documentation if the evaluation results are acceptable.
R6 should be clarified as proposed:
“Each RAS‐entity shall participate in developing a Corrective Action Plan
(CAP) and submit the CAP to its reviewing Reliability Coordinator(s)
within six full calendar months of:”
Also, throughout the standard, references to days and months should
be standardized. There are references to 60 calendar months, 6
calendar months, and 120 calendar days. These time periods should be
expressed in either all months or all days to maintain consistency
throughout the standard.
Response:
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Greg Davis ‐ Greg Davis On Behalf of: Jason Snodgrass, Georgia Transmission Corporation, 1
Answer Comment:
There are multiple registered Planning Coordinators in GTC's Planning
Area, although we joint plan, we would like to propose a simple solution
to ensuring that each Planning Coordinator will become aware of any
new or materially modified RAS within GTC's Planning Area. Additionally
the following rationale is provided to make the basis for our
recommendation:
∙ Not every PC is registered as an RC.
∙ There may be multiple PCs in 1 RC area
∙ PCs that do not own transmission assets may not be aware of new or
functionally modified RAS’s proposed by others and shared only with
the RC
∙ A revision to R1 to include the Planning Coordinator as well is not an
option, because some RAS entity’s may not be aware of multiple PC
registrations in their area.
Therefore, GTC proposes the following new requirement to compliment
the obligations of the Planning Coordinator under requirement R4.
R10(proposed new requirement): Each Reliability Coordinator shall
provide each Planning Coordinator in their Reliability Coordinator area a
copy of the RAS database maintained in accordance with R9, at least
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once every twelve full calendar months.
Additionally, GTC recommends a slight change to requirement R4 to
compliment the new proposed R10 requirement
R4. Each Planning Coordinator that receives a list of RAS’s pursuant to
R10, at least once every 60 full calendar months, shall:
Response:
Jeri Freimuth ‐ APS ‐ Arizona Public Service Co. ‐ 3
Answer Comment:
• To promote clarity and efficiency, AZPS suggests adding the following
to the Rational for Requirement R4 ““Ideally, for a RAS which is
activated in multiple Planning Coordinator areas, a mutually agreed
upon Planning Coordinator of one of the multiple Planning Coordinator
areas shall perform the R4 evaluation.”
• Page 6, foot note 1 defines the limited impact RAS as that which
cannot “cause or contribute” to cascading etc. The word “contribute”
should be removed because it reduces clarity to the standard. The term
“contribute” is too broad and creates challenges to precisely evaluate.
• Attachment 2 I. 6 states that a limited impact RAS is determined by
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the RC. AZPS suggests modifying the language to “…limited impact RAS
as determined by the RC or through a regional review process.” This
will add flexibility to the implementation of the standard and/or allow
for an appeal process to be created, if needed.
Response:
John Merrell ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 1
Answer Comment:
On page 53 of the redlined version of the proposed standard, in the
Technical Justifications for Attachment 1 Content Supporting
Documentation for RAS Review section, II. 6., there does not appear to
be mention of the limited impact exclusion.
Response:
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RFC
Group Name:
Duke Energy
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Group Member Name
Entity
Regio
n
Doug Hils
Duke Energy
RFC
Lee Schuster
Duke Energy
FRCC
Dale Goodwine
Duke Energy
SERC
Greg Cecil
Duke Energy
RFC
Segme
nts
1
3
5
6
Answer Comment:
General Comment: Duke Energy suggests that the drafting team
consider placing the definition of “Remedial Action Scheme” in the
standard for the industry to reference while reviewing the
proposal. The RAS definition is more complex than most other
definitions found in the NERC Glossary and compliance is directly
dependent on the proper application of the RAS definition to a
particular circumstance. Therefore, any future changes to the definition
should be held to the same review and approval process requirements
as the RAS standard itself. This would best be accomplished by
incorporating the definition as an integral part of the
standard. Precedence for this approach already exists in other NERC
standards. Without this approach, it is possible to effectively change
the scope of the NERC standard without due process.
After further discussion, we have concerns regarding the RC being
accountable for the Remedial Action Scheme (RAS) review from a
compliance perspective. The RC is not able to or is not in the position to
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facilitate a review for technical correctness of an RAS, and will be
dependent upon a Planning Coordinator/RAS‐entity to provide this
information. On page 2 of the Question and Answer document supplied
by the drafting team on the project, it is stated;
“The RC is not expected to possess more information or ability than
anticipated by their functional registration as designated by NERC.”
We agree with this sentiment that an entity should not be held
accountable for a product that it is not able to or can readily
provide. However, further down in the same paragraph, the Q & A
document reads;
“The RC may request aid in RAS reviews from other parties such as the
Planning Coordinator(s) or regional technical groups; however, the RC
retains responsibility for compliance with the requirement.”
The drafting team admits that the RC will need assistance from other
entities to perform or provide input for the RAS review. However, the
RC will be held accountable for the accuracy and technical input that
goes into said review. Requiring an entity to be accountable for
information that it may not be able to verify itself is problematic, and
should be revisited. We recommend that the drafting team consider
adding language in the standard stating that the RC will not be held
responsible for the accuracy or content of the technical analysis that is
done by the Planning Coordinator/RAS‐entity. Rather, the RC is
responsible for ensuring that an adequate review is conducted, whether
it is an individual review or coordinated review, merely for “identifying
reliability‐related considerations relevant to various aspects of RAS
design and implementation”, as stated in the Technical Justification for
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Attachment 2 Content. This is a task that the RC would be able to
evaluate and verify itself without relying on the work of another entity
to achieve its compliance.
Response:
Andrew Pusztai ‐ American Transmission Company, LLC ‐ 1
Answer Comment:
ATC has several recommendations for improvement or clarification on
the draft Standard, for consideration by the SDT as listed below:
∙ R4.1.3 and R4.1.4 – These requirements refer to ‘single component
malfunction’ and ‘single component failure’ respectively. However, the
standard does not contain any identification or clarification of which
types of components must be included and which may be excluded in
RAS evaluations. This deficiency could be addressed by including text in
the Supplemental Material section under Requirement 4 that the
drafting team developed for a response in its Consideration of
Comments for Draft 1 of PRC‐012‐2.
“An exhaustive list of components is not practical given the variety that
could be applied in RAS design and implementation. See Item 4a in the
Implementation Section of Attachment 1 in the Supplemental Material
section for typical RAS components for which redundancy may be
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considered. The RAS‐entity should have a clear understanding of what
components were applied to put a RAS into service and which were
already present in the system before a RAS was installed. The RC will
make the final determination regarding which components should be
regarded as RAS components during its review”.
∙ R5 – This requirement does not obligate RAS‐entities to provide
their results of the operational performance analysis of a RAS event to
impacted Transmission Planners and Planning Coordinators. However,
this action should be proposed in the Supplemental Material section.
∙ R6 – This requirement does not obligate RAS‐entities to provide
their Corrective Action Plans to impacted Transmission Planners and
Planning Coordinators. However, this action should be proposed in the
Supplemental Material section.
∙ R8 ‐ The purpose of Version 6 of PRC‐005 was to consolidate all
maintenance and testing of relays under one Standard. Having RAS
testing within PRC‐012‐2 would be contrary to that end. ATC proposes
to address this concern as follows:
Functional testing of RAS (as stated in Requirement 8 of PRC‐012‐2) is a
maintenance and testing activity that would be better included in the
PRC‐005 standard. The present PRC‐005‐6 Reliability Standard is the
maintenance standard that replaces PRC‐005‐1, 008, 011 and 017 and
was designed to cover the maintenance of SPSs/RASs. However, the
current Reliability Standard PRC‐005‐6 lacks intervals and activities
related to non‐protective devices such as programmable logic
controllers. ATC recommends that a requirement for maintenance and
testing of non‐protective RAS components be added to a revision of
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PRC‐005‐6, rather than be an outlying maintenance
requirement located in the PRC‐012‐2 Standard.
If the requirement is not removed and placed in PRC‐005 standard, then
we suggest that wording be added to R8 to refer the entity to meet the
maintenance and testing interval obligations in the latest version of the
PRC‐005 standard.
Response:
Charles Yeung ‐ Southwest Power Pool, Inc. (RTO) ‐ 2
Group Name:
IRC Standards Review Committee
Group Member Name
Entity
Regio
n
Charles Yeung
SPP
SPP
Ben Li
IESO
NPCC
Greg Campoli
NYISO
NPCC
Mark Holman
PJM
RFC
Segme
nts
2
2
2
2
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Matt Goldberg
ISONE
NPCC
2
Lori Spence
MISO
MRO
2
Christina Bigelow
ERCOT
TRE
2
Ali Miremadi
CAISO
WECC 2
Answer Comment:
The rationale Box for R1 contains important guidelines for when a
review of RAS is needed. These should be captured and retained in a
standing Guideline. Also, there should be a need to review a RAS when
the settings that initiate the RAS are changed – which may or may not
be covered by the list of circumstances presented.
In the Applicability section of Attachment 3, the three entities identified
for obligations to PRC‐012‐2 are explained with a concluding caveat that
these entities can collaborate to meet the requirements of the
standard.
“The standard does not stipulate particular compliance methods. RAS‐
entities have the option of collaborating to fulfill their responsibilities
for each applicable requirement. Such collaboration and coordination
may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS‐entity must be able to
demonstrate its participation for compliance. As an example, the
individual RAS‐entities could collaborate to produce and submit a
single, coordinated Attachment 1 to the reviewing RC pursuant to
Requirement R1 to initiate the RAS review material to the process.”
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We ask how will this allowance be included in the RSAW for this
standard?
R6 should be clarified as proposed:
“Each RAS‐entity shall participate in developing a Corrective Action Plan
(CAP) and submit the CAP to its reviewing Reliability Coordinator(s)
within six full calendar months of:”
Also, throughout the standard, references to days and months should
be standardized. There are references to 60 calendar months, 6
calendar months, and 120 calendar days. These time periods should be
expressed in either all months or all days to maintain consistency
throughout the standard.
Response:
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC
Group Name:
Southern Company
Group Member Name
Entity
Regio
n
Segme
nts
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Robert A. Schaffeld
Southern Company Services, Inc.
SERC
1
R. Scott Moore
Alabama Power Company
SERC
3
William D. Shultz
Southern Company Generation
SERC
5
John J. Ciza
Southern Company Generation
and Energy Marketing
SERC
6
Answer Comment:
The owner of any protection scheme should be responsible for the
correct design and implementation of the scheme – RAS or not. Just
like the design of switching to create a blackstart cranking path by a
TOP in EOP‐005‐2, Requirement 6 must be verified by that TOP, the
owner of the RAS should be held to the same expectation that the RAS
is correctly designed and implemented. If the SDT still believes that
some sort of review is required, then that review should be limited in
scope to reviewing the generic content of the RAS design and not delve
into the technical depth identified in some parts of Attachment 2.
Using the criteria outline by the SDT in its recent webinar, in addition to
the independence of the reviewer and geographic span, the team also
mentioned “expertise in planning, protection, operations,
equipment”. The attributes of this expertise to the level expected do
not currently exist in most RC organizations. RC’s are primarily
operating entities (and even then primarily in real‐time) and not experts
in planning (beyond the operating time frame), protection or
equipment. Transmission Owners, Transmission Operators and
Transmission Planners normally have that expertise. The FERC
acknowledged the limited RC technical expertise in evaluating details of
restoration plans in its Order 749, Paragraph 38 (“…basis on which a
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reliability coordinator rejects a restoration plan will necessarily be
based on generic engineering criteria…”). The review of a RAS by an RC
should not be held to a higher expectation due to similar limited
expertise with the equipment and systems involved in a RAS.
The “flexibility” for the RC granted in the requirement to designate a
third party would seem to immediately invalidate the original
assumptions that the RC has the compelling capability to adequately
perform the review while meeting the SDT’s characteristics of the
reviewing entity. To allow this, while still requiring the RC to be
responsible for the review, seems like an improper administrative
burden and a potential compliance risk that the RC may assume
because it had to find an entity more qualified than itself to perform the
review. If an RC is not qualified to review all of the items in Attachment
2 then how can it be held responsible for the results of the review?
Regarding the designation of a third party reviewer, clarification needs
to be made regarding what it means to “retain the responsibility for
compliance.” Does this simply mean that the review takes place or that
there is some implied resulting responsibility for the correct design and
implementation that the RC is now accountable for?
Finally, also regarding the designation of a third party reviewer, is the
term “third party” meant to be any entity not involved in the planning
or implementation of the RAS?
The alternative to using the RC? Although there appears to be a
movement to remove the RRO as a responsible entity from all
standards, those organizations through their membership expertise and
committee structures more closely match the characteristics stated by
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the SDT – expertise in planning/protection/operations/equipment,
independence by virtue of the diversity of its members, wide area
perspective, and continuity. If for some reason the SDT, believes that
the RRO still should not be involved then an alternative could be the
Planning Coordinator function which should have similar expertise to
the Transmission Planners that are to specify/design a RAS per the
functional model yet would have some independence which the SDT is
looking for.
Response:
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer Comment:
Requirement 4 of the standard requires the PC to assess the scheme
once every 60 fully calendar months but the standard doesn’t requires
the RAS entity or RC to provide the PC with the information required to
complete this assessment. Suggest adding an additional requirement
for the RAS entity to provide data required to assessment the RAS
within 30 days of receiving approval from the RC or within 30 calendar
days of receiving a written request from the PC. The PC should also be
receiving the information provided to the RC in R5.2, R6, R7.3.
In Attachment 1 the following information appears to be request twice
under the General and Description and Transmission Planning
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Information. If the drafting team is intending different information be
provided under the Description and Transmission Planning Information,
please consider revising the statement to indicate what is expected.
• General item 4e and Description and Transmission Planning
Information item 1
• General item 4f and Description and Transmission Planning
Information item 2
• General item 4g and Description and Transmission Planning
Information item 5
Response:
Steve Wenke ‐ Avista ‐ Avista Corporation ‐ 5
Answer Comment:
Moving the review of the RAS schemes up to the Reliabilty Coordinator
level does not seem to be the best solution. This responsibility should
fall to the Regional Entity.
Response:
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Si Truc Phan ‐ Hydro‐Qu?bec TransEnergie ‐ 1 – NPCC
Answer Comment:
Why the drafting team has not applied the same approach for RAS
components ? Why non‐protection system components associated to
RAS cannot be subject to PRC‐005 to avoid functional tests like
protection systems components ?
For consistency, all analysis and mitigation of BES protection systems
and RAS should be subject to the same standard. Hydro‐Quebec
TransEnergie suggests removing R5 of PRC‐012 and adding into PRC‐
004.
For consistency, all maintenance and testing requirements of BES
protection and control components, including RAS components, should
be subject to the same criteria. For instance, the requirement R8 of
PRC‐012 does not distinguish monitored versus unmonitored devices.
Hydro‐Quebec TransEnergie suggest removing R8 of PRC‐012 and
adding a table of ‘components used for RAS’ in PRC‐005.
Response:
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Mark Kenny ‐ Eversource Energy ‐ 3
Answer Comment:
Comments: Section 4.1.3 reads “Except for “limited impact”1 RAS, the
possible inadvertent operation of the RAS, resulting from any single RAS
component malfunction satisfies all of the following:” Criteria 4.1.3.1 –
4.1.3.5 follow. Should this requirement also pertain to a failure to
operate, which is the more severe consequence of have a single RAS
component malfunction? Suggest the following wording change:
“Except for “limited impact”1 RAS, the possible inadvertent operation
or failure to operate of the RAS, resulting from any single RAS
component malfunction satisfies all of the following:”
R6, second bullet item presently reads “Notifying the Reliability
Coordinator pursuant to Requirements R5, or”. To be clear, a CAP is
only needed if the RAS fails to operate or if during the evaluation of an
operation, a deficiency is confirmed. Suggest changing the language of
this bullet to “Notifying the Reliability Coordinator of a deficiency or
failure to operate pursuant to Requirements R5.2, or”
Use of the word “cannot” in footnote 1 is too restrictive and onerous
for excluding a RAS from having to comply with the single component
failure requirements in PRC‐012‐2. We suggest the Footnote 1 be
revised to say: “A RAS designated as “limited impact” has been
demonstrated through studies to not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations as a
result of inadvertent operation or failure to operate. See Attachment 2
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for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this
standard that has been through the regional review process and
designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be
recognized as limited impact for the purposes of Requirement 4, Parts
4.1.3 and 4.1.4.”
R8 is vague and subject to interpretation. There are references in the
supplemental material that suggest verification all of the logic in a RAS
PLC on a periodic basis is required and yet in PRC‐005, it’s clear that
there is no need to perform periodic maintenance on relay logic after it
is commissioned. R8 also does not consider fully monitored
components of the RAS such as in PRC‐005.
Attachment 1, II.6 language should be modified similar to comment
above to capture the possible RAS failure to operate due to a single RAS
component malfunction. Suggest new wording: “Documentation
describing the System performance resulting from the possible
inadvertent operation or failure to operate of the RAS, except for
limited impact RAS, caused by any single RAS component malfunction.
Single component malfunctions in a RAS not determined to be limited
impact must satisfy all of the following:”
Attachment 1, III.3. statement appears to be only applicable to “limited
impact” RAS. Wording of this item should be modified to reflect this. A
limited impact RAS will still function correctly when a single component
failure occurs or when a single component is taken out for
maintenance. In all cases, reliability of a RAS scheme is impacted. It is
not realistic to expect that reliability will not be compromised. It is
unclear what the intent of this statement is.
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Response:
Chris Gowder ‐ Chris Gowder On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6
Answer Comment:
FMPA is confused as to why the drafting team considers 60 full calendar
months to be more consistent with PRC‐014‐0 than 5 calendar years,
and views the later as extending the schedule (60 months = 5 years).
FMPA’s previous suggestion (see below) was not to “extend this
schedule”, but to make it more consistent with the annual Planning
Assessment requirements of the TPL standard. A change to 5 calendar
years would allow the Planning Coordinator to conduct their RAS
evaluations in conjunction with their Planning Assessment, even if their
process concludes in a different month in year 5 than it did in year 1.
Requiring 60 calendar months versus 5 calendar years creates an
unnecessary compliance burden that does not enhance reliability. The
revision process should result in a standard that is more consistent with
other active standards than its previous version, especially one that was
never approved by FERC.
From the consideration of comments document…
“RAS Periodic Evaluations: Do you agree with the RAS planning
evaluation process outlined by Requirement R4? If no, please provide
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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134
the basis for your disagreement and an alternate proposal.
Selected Answer: Yes
Answer Comment: Recommend changing 60 full calendar months to 5
calendar years, to allow the RAS evaluation to fit within the annual
Planning Assessment process which may vary from year to year.
Response: Thank you for your comment.
The drafting team based the 60 full calendar months schedule on the
existing PRC‐014‐0, Requirement R1 to perform an assessment “at least
once every five year. . .” The drafting team does not see a convincing
reliability reason to further extend this schedule and declines to make
the suggested change.”
Response:
Brent Ingebrigtson ‐ LG&E and KU Energy, LLC ‐ 1,3,5,6 ‐ SERC
Group Name:
LG&E and KU Energy, LLC
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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135
Group Member Name
Entity
Brent Ingebrigtson
LG&E adn KU energy, LLC
Regio
n
SERC
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Segme
nts
1,3,5,6
Answer Comment:
These comments are submitted on behalf of Louisville Gas and Electric
Company and Kentucky Utilities Company. (“LG&E/KU”). LG&E/KU are
registered in one region (SERC) for one or more of the following NERC
functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.
LG&E/KU strongly support the efforts the Standard Drafting Team has
undertaken to provide in PRC‐012 clear and unambiguous performance
expectations and reliability benefits. LG&E/KU agree that the planning,
design, periodic review, analysis and testing of SPS/RAS schemes are
each essential components of maintaining BES reliability and that
revising PRC‐012 is a necessary and critical step towards that end.
LG&E/KU note that in Section 4 ‐ Applicability of the latest draft of PRC‐
012, the functional entity “Planning Coordinator” has replaced
“Transmission Planner.” LG&E/KU support this change. However, while
the current draft standard requires the Planning Coordinator to
periodically review SPS/RAS schemes within the PC’s planning region,
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136
the draft standard provides no role for the PC in approving any
corrective action plan(s) developed to mitigate whatever threat(s) to
BES reliability the PC’s periodic review may have revealed. Moreover,
and perhaps more importantly, there is likewise no requirement that
the PC approve planned new or modified SPS/RAS schemes to insure
consistency with procedures, protocols, and modeling methodology
utilized with the relevant planning region. These omissions make it
more difficult for the Planning Coordinator to coordinate and integrate
the “transmission facility and service plans, resource plans, and
protection system plans among the Transmission Planner(s) and
Resource Planner(s) within its area of purview.”[1]
LG&E/KU recognize that in some larger planning regions the Planning
Coordinator (“PC”) function may reside within the same organizational
entity as the Transmission Owner (“TO”) or Reliability Coordinator
(“RC”) functions. PRC‐012, however, should function to promote and
maintain BES reliability regardless of how the TO, PC and RC functions
are distributed between organizational entities. Accordingly, LG&E/KU
offer for the SDT’s consideration the following changes to the draft
requirements:
Requirement R1
Prior to placing a new or functionally modified RAS in‐service or retiring
an existing RAS, each RAS‐entity shall provide the information identified
in Attachment 1 for review to the Reliability Coordinator(s) in
consultation with the Planning Coordinator where the RAS is located.
Requirement R2
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137
Each Reliability Coordinator that receives Attachment 1 information
pursuant to Requirement R1 shall, within four full calendar months of
receipt or on a mutually agreed upon schedule, perform a review of the
RAS in accordance with Attachment 2, and provide written feedback
developed in consultation with the Planning Coordinator to each RAS‐
entity.
Requirement R3
Prior to placing a new or functionally modified RAS in‐service or retiring
an existing RAS, each RAS‐entity that receives feedback from the
reviewing Reliability Coordinator(s) identifying reliability issue(s) shall
resolve each issue to obtain approval of the RAS from the RAS‐entity’s
Planning Coordinator and each reviewing Reliability Coordinator.
Requirement R5.2
Provide the results of RAS operational performance analysis that
identified any deficiencies to its reviewing Reliability Coordinator(s) and
Planning Coordinator.
Requirement R6
Each RAS‐entity shall participate in conjunction with the Planning
Coordinator and Reliability Coordinator in developing a Corrective
Action Plan (CAP) and submit the CAP to the RAS‐entity’s Planning
Coordinator and Reliability Coordinator(s) within six full calendar
months of:
Requirement R7.3
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138
Notify each reviewing Reliability Coordinator and Planning Coordinator
if CAP actions or timetables change and when the CAP is completed.
[1] NERC Reliability Functional Model Technical Document — Version 5,
at p.10.
Response:
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7 ‐ NPCC
Group Name:
RSC no Con Edison, Hydro Quebec
Group Member Name
Entity
Regio
n
Paul Malozewski
Hydro One.
NPCC
Guy Zito
Northeast Power Coordinating
NPCC
Council
Segme
nts
1
NA ‐
Not
Applica
ble
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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139
Brian Shanahan
National Grid
NPCC
1
Rob Vance
New Brunswick Power
NPCC
1
Robert J. Pellegrini
United Illuminating
NPCC
1
Edward Bedder
Orange and Rockland Utilities
NPCC
1
Mark J. Kenny
Eversource Energy
NPCC
1
Gregory A. Campoli
NY‐ISO
NPCC
2
Randy MacDonald
New Brunswick Power
NPCC
2
David Burke
Orange and Rockland Utilities
NPCC
3
Wayne Sipperly
New York Power Authority
NPCC
4
David Ramkalawan
Ontario Power Generation
NPCC
4
Glen Smith
Entergy Services
NPCC
4
Brian O'Boyle
Con Edison
NPCC
5
Brian Robinson
Utility Services
NPCC
5
Bruce Metruck
New York Power Authority
NPCC
6
Alan Adamson
New York State Reliability Council
NPCC
7
Kathleen M. Goodman
ISO‐New England
NPCC
2
Helen Lainis
Independent Electricity System
Operator
NPCC
2
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Michael Jones
National Grid
NPCC
3
Silvia Parada Mitchell
NextEra Energy
NPCC
4
Connie Lowe
Dominion
NPCC
4
Answer Comment:
R9 as written requires an update to the database to be made every 12
months. The Measure requires evidence that the database was
updated. This would not address the situation where no update to the
database was required because information did not change.
Reliability Standards usually use the phrase “review the information in
the database and update as necessary”. Then the Measure becomes to
present evidence that the review occurred and if a change occurred
then the database was updated.
Section 4.1.3 reads “Except for “limited impact”1 RAS, the possible
inadvertent operation of the RAS, resulting from any single RAS
component malfunction satisfies all of the following:” Criteria 4.1.3.1 –
4.1.3.5 follow. Should this requirement also pertain to a failure to
operate, which is the more severe consequence of have a single RAS
component malfunction? Suggest the following wording
change: “Except for “limited impact”1 RAS, the possible inadvertent
operation or failure to operate of the RAS, resulting from any single RAS
component malfunction satisfies all of the following:”
R6, second bullet item presently reads “Notifying the Reliability
Coordinator pursuant to Requirements R5, or”. To be clear a CAP is
only needed if the RAS fails to operate or if during the evaluation of an
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operation, a deficiency is confirmed. Suggest changing the language of
this bullet to “Notifying the Reliability Coordinator of a deficiency or
failure to operate pursuant to Requirements R5.2, or”
Use of the word “cannot” in footnote 1 is too restrictive and onerous
for excluding a RAS from having to comply with the single component
failure requirements in PRC‐012‐2. We suggest the Footnote 1 be
revised to say:
“A RAS designated as “limited impact” has been demonstrated by
studies to not cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations as a result of inadvertent operation
or failure to operate. See Attachment 2 for a description of the limited
impact determination by the Reliability Coordinator. A RAS
implemented prior to the effective date of this standard that has been
through the regional review process and designated as Type 3 in NPCC,
Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact
for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4.”
R8 is vague and subject to interpretation. There are references in the
supplemental material that suggest maintenance checking all of the
logic in a PLC on a periodic basis is required and yet in PRC‐005, it’s clear
that there is no need to perform periodic maintenance on relay
logic. R8 also does not consider fully monitored components of the RAS
such as in PRC‐005.
Attachment 1, II.6 language should be modified similar to comment
above to capture the possible RAS failure to operate due to a single RAS
component malfunction. Suggest new wording: “Documentation
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142
describing the System performance resulting from the possible
inadvertent operation or failure to operate of the RAS, except for
limited impact RAS, caused by any single RAS component malfunction.
Single component malfunctions in a RAS not determined to be limited
impact must satisfy all of the following:”
Attachment 1, III.3 statement appears to be only applicable to “limited
impact” RAS. Wording of this item should be modified to reflect this. A
limited impact RAS will still function correctly when a single component
failure occurs or when a single component is taken out for
maintenance. In all cases, reliability of a RAS scheme is impacted. It is
not realistic to expect that reliability will not be compromised. It is
unclear what the intent of this statement is.
While we support the proposed standard as presented, the word
“participate” in Requirements R5, R6 and R8 can lead to confusion and
may result in no entities being held responsible for initiating or leading
the required tasks. As written, the RAS Entity needs only to participate
in such tasks, but it is unclear on whose tasks are they or who leads
these tasks.
We suggest remove the word “participate” from R5, R6 and R8 so that
the RAS Entity is held responsible for analyzing the RAS operational
performance in R5, developing a CAP in R6, and conducting functional
test in R8. Note that the wording in the VSLs for R5, R6 and R8 clearly
indicates that the RAS Entity is responsible for these tasks. Hence, the
word “participate” in the above‐mentioned three requirements is
unnecessary and confusing.
We respectfully requests the STD to consider its previous comment; we
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143
believe that RAS should be reviewed and approved in both the planning
and operating horizons by the designated entities within whose area(s)
the Facility (ies) the RAS is designed to protect reside.
We believes that the term “in‐kind” included in Footnote 4, “Changes to
RAS hardware beyond in‐kind replacement of existing components” is
vague and suggests that the term be clarified such that the reader
knows that the replacement of an electromechanical relay with a
microprocessor relay is construed as an “in kind” replacement, as the
drafting team noted in their December 15th presentation. The concept
of “In‐kind” replacement could be taken a step further. For example, a
discrete ladder logic circuit that includes contacts, overcurrent and
voltage relays could be replaced entirely inside the software logic of a
multifunction device. From a black‐box viewpoint, the old and new RAS
would be identical in function. We also suggests for additional
consideration that the replacement of many discrete components with
a single multifunction component also be considered an “in kind”
replacement so long as for a given set of inputs the “black box”
produces the same outputs as the previous RAS would. In the case of a
breaker failure event, the Standards Drafting Team “SDT” indicates the
need for RAS redundancy even though that would be a double failure
event (failure of the RAS and failure of the breaker). We suggests that it
is sufficiently redundant to use the existing breaker failure relay (non‐
redundant) to initiate both RAS schemes. This can be accomplished by
each RAS using a different contact off the breaker failure relay that was
separately fused.
We suggests the SDT consider using a consistent measure of time,
either calendar months or full calendar days, for responding and
reporting. For example, Requirement 2 states: Each Reliability
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Coordinator that receives Attachment 1 information pursuant to
Requirement R1, shall, within four‐ full‐ calendar months of receipt, or
on a mutually agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written feedback to each
RAS‐entity.” Whereas Requirement 4 states that: “Each RAS entity,
within 120‐ full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with
its reviewing Reliability Coordinator(s), shall:”
Response:
Erika Doot ‐ U.S. Bureau of Reclamation ‐ 5
Answer Comment:
Reclamation appreciates the drafting team’s consolidation of the terms
RAS‐owner and RAS‐entity. Reclamation agrees with defining the RAS‐
entity as the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS.
Reclamation also agrees with the drafting team’s update to
Requirement R6 that each RAS‐entity shall participate in developing a
CAP. Reclamation agrees that this collaboration will promote awareness
of RAS degradation and the efforts and timetables to return the RAS to
service.
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Reclamation supports the proposed change to the definition of SPS.
Response:
Rich Hydzik ‐ Rich Hydzik On Behalf of: Bryan Cox, Avista ‐ Avista Corporation, 5, 3, 1
Scott Kinney, Avista ‐ Avista Corporation, 5, 3, 1
Answer Comment:
PRC‐012‐2 includes some very positive changes for the industry.
In R4.1.3, footnote 1 defines a “limited impact” RAS which does not
require designing to a “no single point of failure” standard. It is a good
thing to have this defined in a NERC standard.
Functional testing requirements defined to be every six years (R8). This
is reasonable.
Evaluation of the need and performance of a RAS every six years is
reasonable (R4).
However, there are concerns that prevent an “affirmative” vote for this
standard.
The Reliability Coordinator is a function is defined as:
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“The entity that is the highest level of authority who is responsible for
the Reliable Operation of the Bulk Electric System, has the Wide Area
view of the Bulk Electric System, and has the operating tools, processes
and procedures, including the authority to prevent or mitigate
emergency operating situations in both next‐day analysis and real‐time
operations. The Reliability Coordinator has the purview that is broad
enough to enable the calculation of Interconnection Reliability
Operating Limits, which may be based on the operating parameters of
transmission systems beyond any Transmission Operator’s vision.”
This supports the concept of the RC reviewing the functionality and
intended use of a RAS. However, a detailed RAS review also includes a
design review of the RAS components and overall system design. This
includes, but is not limited to, substation engineering, relay protection
and design, telecommunication design and performance, and individual
TOP operating practices. The RC’s are familiar with the overall operation
and performance of the BES. The RC’s skill set generally does not
include those technical specialties required for a detailed review of the
design of a RAS.
This follows that the evaluation of a RAS misoperation should be
performed by a different entity than the RC. While the RC certainly can
evaluate the performance of the RAS and identify that a misoperation
occurred, the RC’s skill set does not allow for a thorough review of the
RAS problem or potential solutions. Further, implementing a Corrective
Action Plan under the supervision of the RC does not seem appropriate.
This places the RC in an engineering, maintenance, and enforcement
role that does not appear to be with the RC function.
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The intent of the standard is sound. Implementation among the
Reliability Entities needs further development.
Response:
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer Comment:
Degraded RAS
As Texas RE mentioned in the comments for the initial ballot, Texas RE
recommends a requirement to report the degraded RAS to the
RC. Texas RE noticed the referenced Standards/Requirements (i.e.,
Supplemental Material indicates PRC‐001 R6 and TOP‐001‐2 R5) are
either being retired or are not explicit enough to ensure that the
reliability of the system is maintained for those who should have
situational awareness. PRC‐001 R6 is being retired and translated to
TOP‐001‐3 R10 and R11 which applies to ONLY the TOP and BA not the
RC. While TOP‐003‐3 states a BA and TOP “shall distribute its data
specification to entities that have data required by the” respective
functions and analysis (e.g., Real‐time monitoring, Operational Planning
Analyses), there is no requirement to provide the RAS status to the
RC.
Requirement R8
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Texas RE is concerned introducing a six year functional testing
requirement for a RAS is too long to ensure reliability of a system
because reliability is at stake for the RAS to be in place. This extended
timeframe may disregard PRC‐005 components that may have shorter
timeframes for maintenance or cause confusion to the entities
responsible for said maintenance. While the RAS‐entity will have PRC‐
005 obligations, it should not be considered the same as functional
testing of the RAS if the PRC‐005 components are ignored, overlooked,
or not reviewed. Coordinated functional testing should be required for
multi‐RAS‐entity owned RASs. Without coordination, there is not a
clear reliability path to ensure overall performance and the proper
operation of ALL RAS components.
Texas RE seeks clarity on the rationale for Requirement R8. It does not
seem to reflect a coherent approach to reliability when discussing
resetting the “test interval clock for that segment”. The Requirement is
written for the RAS not segments of the RAS. The phrase “of its” that
was added increases ambiguity and may cause confusion among RAS‐
entities in a multi‐owned component RAS. Texas RE recommends
requiring coordination of functional testing for RASs with components
owned by more than one RAS‐entity. Individualized non‐coordinated
functional testing of RAS components will not be a functional test of the
RAS.
Full Calendar Months
The SDT introduces a new term “full calendar months” that is not
defined and is inconsistent with other Reliability Standards. Texas Re
recommends the SDT provide the definition within the auspices of the
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Standards process while considering other definitions already in place
(such as “Calendar Year” in PRC‐005‐2).
Corrective Action Plan
Texas RE recommends revising PRC‐12‐2, R7 to place at least minimal
criteria around modifications to Corrective Action Plans (CAP) or
corresponding CAP timetables. As currently drafted, PRC‐12‐2, R7 could
be interpreted to permit RAS‐entities to perpetually update their CAPs if
“actions or timetables change” and then merely notify the RC of such
changes. Texas RE recommends that the SDT consider some minimal
criteria that RAS‐entities must satisfy in order to update a CAP under
PRC‐12‐2, R7.2. For instance, PRC‐12‐2, R7.2 could be revised to read:
“Update the CAP for any reasonable changes in the required actions or
implementation timetable.” In turn, PRC‐12‐2, R7.3 could be revised to
read: “Notify each reviewing Reliability Coordinator and provide a
reasoned justification for changes in CAP actions or timetables, and
notify each reviewing Reliability Coordinator when the CAP is
completed.”
RAS‐entity definition
The current draft of PRC‐12‐2 defines the term “RAS‐entity” in the
Technical Justifications for Requirements section. Texas RE
recommends that the SDT consider incorporating this definition into the
language of PRC‐12‐2 itself or into the NERC Glossary of Terms.
Misoperations
In Requirement R5, what constitutes a RAS operation or
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misoperation? The NERC SPCS created a draft template in 2014 for
reporting RAS operations and misoperations where they defined a
misoperation as “Failure to Operate”, “Unnecessary Operation”,
“Unintended System Response”, and “Failure to Mitigate”. These were
draft terms and have not been incorporated into any Standard or the
NERC Glossary. Arming and disarming of a RAS were not included in the
SPCS RAS template. The items listed in 5.1.1 through 5.1.4 somewhat
mirror the SPCS RAS template, is it the SDT’s intent that 5.1.1 through
5.1.4 are intended to be the definition of a RAS
operation/misoperation? If so, Texas RE suggests these would be better
suited in the NERC Glossary than within the Standard.
Also reporting of Misoperations for Protection Systems will be
contained with the Section 1600 Data Request for PRC‐004. There is no
requirement within PRC‐012 or the Section 1600 data request for
reporting Misoperations of a RAS to the Regional Entities or
NERC. Texas RE recommends the SDT consider this.
Response:
Dennis Chastain ‐ Dennis Chastain On Behalf of: Brandy Spraker, Tennessee Valley Authority, 6, 1, 5, 3
Answer Comment:
1. Numerous entities, including TVA, have previously commented that
the responsibility for reviewing and approving new or functionally
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modified RAS schemes belongs with the Planning Coordinator and not
the Reliability Coordinator. According to the NERC Reliability Functional
Model ‐ Version 5, the Planning Coordinator is defined as the, “…entity
that coordinates, facilitates, integrates and evaluates (generally one
year and beyond) transmission facilities and services plans, and
resource plans within a Planning Coordinator area and coordinates
those plans with adjoining Planning Coordinator areas.” The model
specifically includes the evaluation of transmission facilities in the
planning horizon. Conversely, the Reliability Coordinator is responsible
for maintaining the Real‐time reliability of the Bulk Electric System. It
was never contemplated that the Reliability Coordinator would have
oversight over the planning of the Bulk Electric System or the entities
responsible for Bulk Electric System planning. The drafting team’s
response to TVA’s comments states that the Reliability Coordinator has
the “widest‐area reliability perspective of all functional entities” and
that the “NERC Functional Model is a guideline” and does not preclude
the drafting team from addressing functions not described in the
Functional Model. From TVA’s perspective, however, the proposed
standard, as written, is in direct conflict with the Functional Model, and
requires a compelling reason to justify the deviation. The facts that
there are fewer Reliability Coordinators (as opposed to Planning
Coordinators) and that the Reliability Coordinators have the “widest‐
area view” do not support a significant deviation from the Functional
Model. Moreover, such analysis would beyond the normal Reliability
Coordinator functions, the Reliability Coordinators would not have the
expertise to conduct RAS analysis in the planning horizon. Simply put,
Reliability Coordinators do not have trained personnel or the
appropriate tools to complete a comprehensive assessment. Planning
Coordinators have oversight over all other aspects of planning of the
Bulk Electric System, and there is no reason to treat Remedial Action
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Schemes differently.
R6 requires the “RAS‐entity” to develop Corrective Action Plans if there
is a deficiency in its 5‐year RAS evaluation (R4), its post‐event analysis
(R5), or its 6‐year functional testing (R8), and to submit those
Corrective Action Plans to the Reliability Coordinator for review. The
proposed standard, however, does not give the Reliability Coordinator
any authority to approve or deny the Corrective Action Plan. If the
Corrective Action Plan is inadequate or changes the RAS to cause a
negative impact on a wider area of the BES, the Reliability Coordinator
must be able to reject the Corrective Action Plan and require a revised
plan.
Response:
Eric Olson ‐ Transmission Agency of Northern California ‐ 1
Answer Comment:
TANC appreciates the drafting team’s response to our prior comments
and the corresponding changes to the standard regarding the
potentially overlapping responsibilities of multiple Transmission
Owners, Generator Owners and Distribution Providers that each own
portions of a single RAS. In its response to TANC’s prior comments, the
drafting team stated that each RAS‐entity “is responsible only for its
RAS components.” The second draft of the standard is not so clear on
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this issue, however, as the requirements only refer to each RAS‐entity’s
responsibility for “its RAS”. TANC requests that NERC replace “its RAS”
with “its RAS components” in the requirements of the standard to
clarify the responsibilities of each party. TANC believes that inserting
this distinction into the language of the requirements would more
clearly convey that multiple parties may have compliance responsibility
for their respective “components” of a single RAS, but each party is not
responsible for the entirety of the RAS.
TANC notes that the “Reliability Standard PRC‐012‐2 Remedial Action
Schemes Question & Answer Document” document dated November
2015 appears to incorrectly reference the Transmission Owner (TO)
function in the first paragraph of Section 3. References in that
paragraph were made to TO roles and responsibilities that are
purportedly established within standards TOP‐001‐3 and IRO‐005‐4, but
those two standards establish roles and responsibilities for the
Transmission Operator (TOP) function, not the TO function.
Response:
Mark Wilson ‐ Independent Electricity System Operator ‐ 2 ‐ NPCC
Answer Comment:
While we support the proposed standard as presented, the word
“participate” in Requirements R5, R6 and R8 can lead to confusion and
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may result in no entities being held responsible for initiating or leading
the required tasks. As written, the RAS Entity needs only to participate
in such tasks, but it is unclear on whose tasks are they or who leads
these tasks.
We suggest to remove the word “participate” from R5, R6 and R8 so
that the RAS Entity is held responsible for analyzing the RAS operational
performance in R5, developing a CAP in R6, and conducting functional
test in R8. Note that the wording in the VSLs for R5, R6 and R8 clearly
indicates that the RAS Entity is responsible for these tasks. Hence, the
word “participate” in the above‐mentioned three requirements is
unnecessary and confusing.
Response:
Oshani Pathirane ‐ Oshani Pathirane On Behalf of: Paul Malozewski, Hydro One Networks, Inc., 1, 3
Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3
Answer Comment:
While Hydro One Networks Inc. is generally in support of the direction
the standard takes and although the third revision (Draft 2‐ November
2015) presents improvement (with the introduction of the concept of
“limited impact RAS” and recognition of RAS typing), requirement R8
and several choices in wording remain a concern. Hydro One believes
that a level of testing similar to that required in the PRC‐005 series
would be more appropriate for R8. With a level of testing specified in
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Comment #1 below, a high VRF, similar to that designated in the PRC‐
005 series would be appropriate and hence although Hydro One has
cast a negative ballot on the standard, we are in support of the poll
associated with the VRFs and VSLs. We hope the comments provided
below will be of added value to the drafting team:
1. R8 is vague and subject to interpretation. There are references in
the supplemental material that suggest maintenance and checking of
all the logic in a PLC on a periodic basis is required, and yet, in PRC‐005,
it is clear that there is no need to perform periodic maintenance on
relay logic. For monitored components, such as microprocessor relays,
the “verification of settings [as] specified” in PRC‐005 (i.e., performing a
settings compare) should be sufficient rather than implying that all logic
needs to be re‐verified. For RAS not designated as limited‐impact, R8
does not distinguish between monitored and unmonitored components
of the RAS such as distinguished in PRC‐005, which would allow a RAS‐
entity to have a 12‐year maintenance interval for monitored
components.
2. R5.1 – The usage of the term “[p]articipate” does not define
accountability. The standard should clearly identify who is accountable
for what activity. For consistency, we suggest using verbiage similar to
that used in PRC‐004‐4’s description of accountabilities in the case of
owning Shared Protection Systems.
3. R5.1.3 & R5.1.4 are related to performance of RAS and its impact
on the BES. This assessment is better suitable for the PC or RC to
conduct.
4. R5.2 – “Each RAS‐entity shall provide results (…) to RC”. In the case
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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156
that a RAS is owned by more than one entity, it is unclear from the
verbiage which entity is accountable to communicate with the RC and
maintain evidence of such activity. The standard should clearly identify
who is accountable for what activity. For consistency, we suggest using
verbiage similar to that used in PRC‐004‐4’s description of
accountabilities in the case of owning Shared Protection Systems.
5. R6 ‐ “ Each RAS‐entity shall participate” ‐ Similar to the comments
submitted above for R5, the usage of the term “[p]articipate” does not
define accountability. The standard should clearly identify who is
accountable for what activity. For consistency, we suggest using
verbiage similar to that used in PRC‐004‐4’s description of
accountabilities in the case of owning Shared Protection Systems.
6. “Each RAS‐entity shall submit the CAP to RC” ‐ Similar to the
comments submitted above for R5, in the case that a RAS is owned by
multiple entities, it is unclear from the verbiage which entity is
accountable to communicate with the RC and maintain evidence of such
activity.
7. R5 – It is unclear from the wording whether the RAS‐entity would
“[p]articipate in analyzing the RAS operational performance” with the
RC, or only mutually agree upon a schedule for such activity with the
RC.
8. R4.1.4 ‐ When a RAS is used to respond to an event, e.g. category
P1 in TPL‐001‐4, its failure should be considered to be a more severe
event, just as in TPL‐001‐4, the failure of a breaker or protection relay
following a P1 event is recognized as “Multiple Contingency” (category
P3 and P4). For this reason, the system performance with a RAS failure
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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157
should not be required to meet the exact same requirements as those
for the original event (defined in TPL‐001‐4). Therefore, we suggest
deleting R4.1.4 and instead revising R4.1.3 to read “Except for “limited
impact”1 RAS, the possible inadvertent operation of the RAS, or failure
of the RAS to operate, resulting from any single RAS component
malfunction satisfies all of the following:”
9. RAS‐entity: The standard should clearly define accountabilities in
the case of a RAS scheme being owned by multiple entities.
10. R2 – We suggest specifying which entity the RC will be mutually
agreeing upon a schedule with: “on a schedule mutually agreed upon
with the RAS‐entity,….”
Hydro One Networks Inc. also generally supports the comments the
NPCC has submitted.
Response:
Andrea Jessup ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer Comment:
R2: BPA maintains that the allowance of up to four full calendar months
for the RC to perform the RAS review is unreasonable and not in line
with current regional practice.
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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158
Currently in WECC, RAS information for new or functionally modified
schemes (this information is equivalent to Attachment 1 and 2) is
provided two weeks in advance of scheduled WECC RAS RS
meetings. At those meetings, all details of the RAS are presented,
reviewed, and approved/disapproved. The review is at the final stages
of the design process, just prior to construction/energization. By
requiring Attachment 1, and Attachment 2, and allowing the RC four full
calendar months review time, it appears that four months is being
added to the entire process of placing a RAS in service. This additional
four month delay may constrain the energization of variable generation
resources.
Regarding Attachment 2: “The RC review is not limited to the checklist
items and the RC may request additional information on any aspect of
the RAS as well as any reliability issue related to the RAS.” BPA
believes this presents an open‐ended opportunity to increase the four
month review window, because you can’t go in service without prior
approval of the RAS.
Attachment 2. II. 2. “The timing of RAS actions(s) is appropriate to its
BES performance objectives.” This makes sense, but often timing of a
RAS cannot be proven until the RAS is built and functionally
tested. Historically in WECC, you are aware of the timing constraints
required for RAS operation, you provide an estimate of the timing, and
you’re provided “conditional approval” to go operational with a future
action item presented to the WECC RAS RS that validates the timing is
within constraints. Item 2 implies that a RAS‐entity has to prove the
timing prior to going in service, which isn’t reasonable. That basically
means that the RAS‐entity has to build the scheme, test it, and then go
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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159
get it approved.
Attachment 2. II. 4. “The RAS design facilitates periodic testing and
maintenance.” BPA believes this is subjective; does this mean that the
RC would require a standard method for periodic testing and
maintenance? This appears open to interpretation.
The four full calendar months appears to create the opportunity for a
large increase in workload and back and forth discussion between the
RC and the utility designing the RAS.
R3: BPA proposes the requirement allow for conditional approval.
Response:
Ben Engelby ‐ ACES Power Marketing ‐ 6
Group Name:
ACES Standards Collaborators ‐ PRC‐012‐2 Project
Group Member Name
Entity
Regio
n
Ellen Watkins
Sunflower Electric Power
SPP
Corporation
Segme
nts
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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160
Shari Heino
Ginger Mercier
Brazos Electric Power Cooperative, TRE
Inc.
Prairie Power, Inc.
SERC
1,3
Mark Ringhausen
Old Dominion Electric Cooperative RFC
3,4
Ryan Strom
Buckeye Power, Inc.
RFC
4
Matt Caves
SPP
1,5
Kevin Lyons
Western Farmers Electric
Cooperative
Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.
and Southwest Transmission
Cooperative, Inc.
Central Iowa Power Cooperative
MRO
1
Mike Brytowski
Great River Energy
MRO
1,3,5,6
John Shaver
1,5
WECC 1,4,5
Answer Comment:
(1) We agree with the SDT’s consolidation of the reliability objectives of
the six existing RAS/SPS related standards into one standard PRC‐012‐2.
(2) The SAR for revising TPL‐001‐4 for single points of failure may
overlap with PRC‐012‐2. We recommend the SDT meet with the SAR
team to discuss the scope and potential for overlap that could lead to
double jeopardy. We recommend that NERC staff also research this
issue.
(3) RAS‐entity causes confusion for entities that have joint ownership of
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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161
a RAS. We recommend the SDT develop guidance to support the
requirements and expectations for joint owners to meet
compliance. For RAS with multiple RAS‐entities, who is responsible for
overall coordination to assure complete and consistent data submittals
in order to meet compliance with this standard? The SDT has left this
silent, which may result in joint entities not cooperating, not sharing
documentation, etc.
(4) Corrective Action Plans need to be clarified as to what triggers
would qualify as a “deficiency” that would require a CAP to be
developed. We also have concerns relating to coordination of CAPs that
are developed for a jointly‐owned RAS.
(5) We believe the VSLs for this standard could be better defined. The
incremental scale between one criteria (e.g., R4 has 60, 61, 62, 63
calendar months for ranges from Lower to Severe) to the next for
several VSLs are too condensed. We also believe a graduated scale for
Requirements R1 and R3 could be provided.
(6) We agree that the RC is the best‐suited entity to perform the RAS
reviews. However, we recommend that the SDT actively work with RCs
to ensure they are aware of the proposed requirements and have the
resources to support them.
(7) We agree that the PC has a broader view compared to the TP and is
the proper entity for RAS periodic evaluations.
(8) Finally, we ask NERC to consider the holiday schedule when posting
standards for comment. There are several industry groups that
coordinate comments a week or two prior to final submission to the
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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162
SDT, and having to coordinate comments over the holidays is difficult
with vacation schedules. We ask the drafting teams to consider
delaying posting so the deadline is the second or third week in January,
allowing the industry groups enough time to coordinate during the
weeks prior to the due date.
(9) Thank you for the opportunity to comment.
Response:
Phil Hart ‐ Associated Electric Cooperative, Inc. ‐ 1
Group Name:
AECI
Group Member Name
Entity
Mark Ramsey
N.W. Electric Power Cooperative,
Inc.
John Stickley
N.W. Electric Power Cooperative,
Inc.
Kevin White
Northeast Missouri Electric Power
Cooperative
Regio
n
SERC
Segme
nts
1
SERC
3
SERC
1
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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163
Skyler Wiegmann
SERC
Walter Kenyon
Northeast Missouri Electric Power
Cooperative
Central Electric Power
Cooperative
Central Electric Power
Cooperative
Sho‐Me Power Electric
Cooperative
Sho‐Me Power Electric
Cooperative
KAMO Electric Cooperative
SERC
1
Theodore J Hilmes
KAMO Electric Cooperative
SERC
3
Phillip B Hart
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
Associated Electric Cooperative
Inc.
SERC
1
Michael B Bax
Adam M Weber
Denise Stevens
Jeff L Neas
Todd Bennett
Matt Pacobit
Brian Ackermann
3
SERC
1
SERC
3
SERC
1
SERC
3
SERC
3
SERC
5
SERC
6
Answer Comment:
AECI is in agreement with multiple commenters who have issue with
this current version.
Response:
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164
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2
Answer Comment:
ERCOT supports the comments submitted by the IRC SRC and provides
these additional comments.
As noted above, ERCOT no longer uses the “Type 2” RAS designation,
and this reference should be removed from the footnotes and rationale
boxes in this draft standard.
R6 should be reworded to clarify compliance obligations for the RAS‐
entity. ERCOT suggests the following language:
“Each RAS‐entity shall develop a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full
calendar months of:...."
Additionally, the references to days and months should be
standardized. There are references to 60 calendar months, 6 calendar
months, and 120 calendar days. The SDT should consider expressing all
of these time periods in the same units—using either months or days to
maintain consistency throughout the standard.
Response:
Consideration of Comments | 2010‐05.3 Phase 3 of Protection Systems: RAS | PRC‐012‐2 and Definition
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165
Jared Shakespeare ‐ Peak Reliability ‐ 1
Answer Comment:
There needs to be some mechanism in place (possibly a requirement) to
ensure that RAS functionality and coordination issues are addressed in
response to physical changes to the system, e.g., removing or adding
transmission or generation Facilities. A reliability gap can be created if
the physical system is changed, but RAS are not updated or modified in
response to those physical system changes. Without a functional
modification to the RAS it would not perform according to its intended
design. The five year review process cannot be relied upon to address
these scenarios, as it would result in long‐term exposure to reliability
risks.
Example scenario:
{C}∙ A RAS exists in an area to prevent voltage collapse
{C}∙ An entity retires a generation Facility which is associated with
the RAS
{C}∙ The RAS is not updated to account for the retirement of the
generation Facility
{C}∙ The RAS is rendered ineffective for preventing voltage collapse
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166
{C}∙ This condition is not discovered until the PC performs its 5‐year
review
{C}∙ Until the PC performs its 5‐year review, the system is
vulnerable to voltage collapse due to RAS ineffectiveness
Both R4.1.4 and Attachment 1, section III, item 4 use the same
confusing language, “a single component failure in the RAS, when the
RAS is intended to operate does not prevent the BES from meeting the
same performance requirements (defined in Reliability Standard TPL‐
001‐4 or its successor) as those required for the events and conditions
for which the RAS is designed.” Though similar language is used in the
currently effective set of reliability standards, it is confusing and
unclear. We recommend clarifying the language and/or providing
examples in an application guideline as part of the standard itself that
might help the reader understand the meaning of and intent behind this
language.
In R2 RC is required to follow Attachment 2 for the evaluation, what is
the required evaluation for the PC in R4? Is it Attachment 2 as well?
For R5 when a RAS operation, failure to operate, or mis‐operation
occurs, and a deficiency is identified, the RAS should be removed from
service until the CAP is implemented.
Response:
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167
End of report
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168
PRC‐012‐2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 2 of PRC‐012‐2 corrects the applicability of the fill‐in‐the‐blank standards (PRC‐012‐1,
PRC‐013‐1, and PRC‐014‐1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk‐Power System, and incorporates the reliability objectives of
all the RAS‐related standards. This draft contains nine requirements and measures, the
associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. This draft of PRC‐012‐2 is posted for a 45‐day formal comment period with a
parallel ballot in the last ten days of the comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC‐012‐2 posted for informal comment
April 30 – May 20, 2015
45‐day formal comment period with initial ballot
August 20 – October 5,
2015
45‐day formal comment period with additional ballot
November 25, 2015 –
January 8, 2016
45‐day formal comment period with additional ballot
February 3, 2016 –
March 18, 2016
Anticipated Actions
Date
10‐day final ballot
April 2016
NERC Board (Board) adoption
May 2016
Draft 3 of PRC‐012‐2
February 2016
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PRC‐012‐2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
3.
Number:
Purpose:
PRC‐012‐2
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Planning Coordinator
4.1.3. RAS‐entity – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC‐012‐2.
Draft 3 of PRC‐012‐2
February 2016
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PRC‐012‐2 – Remedial Action Schemes
B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement; i.e., removal from service must be completed prior
to implementation or retirement.
Functional modifications consist of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original
functionality of existing components
Changes to RAS logic beyond correcting existing errors
Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS‐entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS‐entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. Ideally, when there is more than one RAS‐entity for
a RAS, the RAS‐entities would collaborate and submit a single, coordinated Attachment 1
to the reviewing RC. In cases where a RAS crosses RC Area boundaries, each affected RC is
responsible for conducting either individual reviews or participating in a coordinated
review.
R1.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest‐area operational and reliability perspective of all
functional entities and an awareness of reliability issues in any neighboring RC Area. This
Wide Area purview facilitates the evaluation of interactions among separate RAS as well
as interactions among RAS and other protection and control systems. Review by the RC
also minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP),
or other entities that are likely to be involved in the planning or implementation of a RAS.
The RC is not expected to possess more information or ability than anticipated by their
Draft 3 of PRC‐012‐2
February 2016
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PRC‐012‐2 – Remedial Action Schemes
functional registration as designated by NERC. The RC may request assistance to perform
RAS reviews from other parties such as the PC or regional technical groups; however, the
RC will retain the responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each submitted RAS.
The time frame of four full calendar months is consistent with current utility and regional
practice; however, flexibility is provided by allowing the RC(s) and RAS‐entity(ies) to
negotiate a mutually agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to each RAS‐entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS‐entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in‐service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS‐entity to respond to the reviewing RC following
identification of any reliability issue(s) is not necessary because the RAS‐entity wants to
expedite the timely approval and subsequent implementation of the RAS.
A specific time period for the RC to respond to the RAS‐entity following the RAS review is
also not necessary because the RC will be aware of (1) any reliability issues associated
with the RAS not being in service and (2) the RAS‐entity’s schedule to implement the RAS
to address those reliability issues. Since the RC is the ultimate arbiter of BES operating
reliability, resolving reliability issues is a priority for the RC and serves as an incentive to
expeditiously respond to the RAS‐entity.
R3.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability Coordinator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
Draft 3 of PRC‐012‐2
February 2016
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PRC‐012‐2 – Remedial Action Schemes
were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every five full calendar years. The purpose of the periodic RAS
evaluation is to verify the continued effectiveness and coordination of the RAS, as well as
to verify that, if a RAS single component malfunction or single component failure were to
occur, the requirements for BES performance would continue to be satisfied. A periodic
evaluation is required because changes in System topology or operating conditions may
change the effectiveness of a RAS or the way it impacts the BES.
RAS are unique and customized assemblages of protection and control equipment that
vary in complexity and impact on the reliability of the BES. In recognition of these
differences, RAS can be designated by the reviewing RC(s) as limited impact. A limited
impact RAS cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations. Limited impact RAS are not subject to the
RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5, respectively.
Requiring a limited impact RAS to meet these tests would add complexity to the design
with minimal benefit to BES reliability. See the Supplemental Material for more on the
limited impact designation.
The limited impact designation is modeled after the Local Area Protection Scheme (LAPS)
classification in WECC (Western Electricity Coordinating Council) and the Type 3
classification in NPCC (Northeast Power Coordinating Council). A RAS implemented prior
to the effective date of PRC‐012‐2 that has been through the regional review processes of
WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC
or a Type 3 in NPCC is recognized as a limited impact RAS upon the effective date of PRC‐
012‐2 for the purposes of this standard and is subject to all applicable requirements.
For existing RAS, the initial performance of Requirement R4 must be completed within
five full calendar years of the effective date of PRC‐012‐2. For new or functionally
modified RAS, the initial performance of the requirement must be completed within five
full calendar years of the RAS approval date by the reviewing RC(s). Five full calendar
years was selected as the maximum time frame between evaluations based on the time
frames for similar requirements in Reliability Standards PRC‐006, PRC‐010, and PRC‐014.
The RAS evaluation can be performed sooner if it is determined that material changes to
System topology or System operating conditions could potentially impact the
effectiveness or coordination of the RAS. System changes also have the potential to alter
the reliability impact of limited impact RAS on the BES. Requirement 4, Part 4.1.3
explicitly requires the periodic evaluation of limited impact RAS to verify the limited
impact designation remains applicable. The periodic RAS evaluation will typically lead to
one of the following outcomes: 1) affirmation that the existing RAS is effective; 2)
identification of changes needed to the existing RAS; or, 3) justification for RAS
retirement.
Draft 3 of PRC‐012‐2
February 2016
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PRC‐012‐2 – Remedial Action Schemes
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1
through 4.1.5) are planning analyses that may involve modeling of the interconnected
transmission system to assess BES performance. The Planning Coordinator (PC) is the
functional entity best suited to perform this evaluation because they have a wide area
planning perspective. To promote reliability, the PC is required to provide the results of
the evaluation to each impacted Transmission Planner and Planning Coordinator, in
addition to each reviewing RC and RAS‐entity. In cases where a RAS crosses PC
boundaries, each affected PC is responsible for conducting either individual evaluations
or participating in a coordinated evaluation.
The previous version of this standard (PRC‐012‐1 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL‐001‐
0, TPL‐002‐0, and TPL‐003‐0) as that required of the Contingency for which it was
designed, and not exceed TPL‐003‐0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise,
consistent with PRC‐012‐1 Requirement 1, R1.4, the RAS should be designed so that its
whole or partial inadvertent operation due to a single component malfunction satisfies
the System performance requirements for the same Contingency for which the RAS was
designed.
If the RAS was installed for an extreme event in TPL‐001‐4 or for some other Contingency
or System condition not defined in TPL‐001‐4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL‐001‐4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.1.3.1 – 4.1.3.5) are the ones that
are common to all planning events P0‐P7 listed in TPL‐001‐4.
R4.
Each Planning Coordinator, at least once every five full calendar years, shall: [Violation
Risk Factor: Medium] [Time Horizon: Long‐term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for which
it was designed.
4.1.2. The RAS avoids adverse interactions with other RAS, and protection and
control systems.
Draft 3 of PRC‐012‐2
February 2016
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PRC‐012‐2 – Remedial Action Schemes
4.1.3. For limited impact1 RAS, the inadvertent operation of the RAS or the
failure of the RAS to operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations.
4.1.4. Except for limited impact RAS, the possible inadvertent operation of the
RAS, resulting from any single RAS component malfunction satisfies all of
the following:
4.1.4.1.
The BES shall remain stable.
4.1.4.2.
Cascading shall not occur.
4.1.4.3.
Applicable Facility Ratings shall not be exceeded.
4.1.4.4.
BES voltages shall be within post‐Contingency voltage limits
and post‐Contingency voltage deviation limits as established
by the Transmission Planner and the Planning Coordinator.
4.1.4.5.
Transient voltage responses shall be within acceptable limits
as established by the Transmission Planner and the Planning
Coordinator.
4.1.5. Except for limited impact RAS, a single component failure in the RAS,
when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS‐entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS‐entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations.
1
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Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation was
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4
regarding the investigation of a Protection System Misoperation. To promote reliability,
each RAS‐entity is required to provide the results of RAS operational performance
analyses that identified any deficiencies to its reviewing RC(s).
RAS‐entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly
(Part 5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response
(Parts 5.1.3 and 5.1.4) was consistent with the intended functionality and design of the
RAS. Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would
collaborate to conduct and submit a single, coordinated operational performance
analysis.
R5.
Each RAS‐entity, within 120 full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.1. The System events and/or conditions appropriately triggered the RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with participating RAS‐entities and the reviewing Reliability Coordinator(s) in
accordance with Requirement R5.
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PRC‐012‐2 – Remedial Action Schemes
Rationale for Requirement R6: Deficiencies identified in the periodic RAS evaluation
conducted by the PC pursuant to Requirement R4, in the operational performance
analysis conducted by the RAS‐entity pursuant to Requirement R5, or in the functional
test performed by the RAS‐entity pursuant to Requirement R8, potentially pose a
reliability risk to the BES. To mitigate these potential reliability risks, Requirement R6
mandates that each RAS‐entity develop a Corrective Action Plan (CAP) to address the
identified deficiency. The CAP contains the mitigation actions and associated timetable
necessary to remedy the specific deficiency. The RAS‐entity may request assistance with
CAP development from other parties such as its Transmission Planner or Planning
Coordinator; however, the RAS‐entity has the responsibility for compliance with this
requirement.
If the CAP requires that a functional change be made to a RAS, the RAS‐entity will need to
submit information identified in Attachment 1 to the reviewing RC(s) prior to placing RAS
modifications in‐service per Requirement R1.
Depending on the complexity of the identified deficiency(ies), development of a CAP may
require studies, and other engineering or consulting work. A maximum time frame of six
full calendar months is specified for RAS‐entity collaboration on the CAP development.
Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would
collaborate to develop and submit a single, coordinated CAP.
R6.
Each RAS‐entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐
term Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency pursuant to Requirement R5,
Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS‐entity in
accordance with Requirement R6.
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PRC‐012‐2 – Remedial Action Schemes
Rationale for Requirement R7: Requirement R7 mandates each RAS‐entity implement a
CAP (developed in Requirement R6) that mitigates the deficiencies identified in
Requirements R4, R5, or R8. By definition, a CAP is: “A list of actions and an associated
timetable for implementation to remedy a specific problem.” The implementation of a
properly developed CAP ensures that RAS deficiencies are mitigated in a timely manner.
Each reviewing Reliability Coordinator must be notified if CAP actions or timetables
change, and when the CAP is completed.
R7.
Each RAS‐entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the reviewing Reliability
Coordinator(s) that documents the implementation, updating, or completion of a CAP
in accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non‐Protection System (control) components of a RAS that are not addressed in PRC‐005.
Protection System components that are part of a RAS are maintained in accordance with
PRC‐005.
The six or twelve full calendar year test interval, which begins on the effective date of the
standard pursuant to the PRC‐012‐2 implementation plan, is a balance between the
resources required to perform the testing and the potential reliability impacts to the BES
created by undiscovered latent failures that could cause an incorrect operation of the
RAS. Extending to longer intervals increases the reliability risk to the BES posed by an
undiscovered latent failure that could cause an incorrect operation or failure of the RAS.
The RAS‐entity is in the best position to determine the testing procedure and schedule
due to its overall knowledge of the RAS design, installation, and functionality. Functional
testing may be accomplished with end‐to‐end testing or a segmented approach. For
segmented testing, each segment of a RAS must be tested. Overlapping segments can be
tested individually negating the need for complex maintenance schedules and outages.
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February 2016
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PRC‐012‐2 – Remedial Action Schemes
The maximum allowable interval between functional tests is six full calendar years for RAS
that are not designated as limited impact RAS and twelve full calendar years for RAS that
are designated as limited impact RAS. The interval between tests begins on the date of
the most recent successful test for each individual segment or end‐to‐end test. A
successful test of one segment only resets the test interval clock for that segment. A
correct operation of a RAS qualifies as a functional test for those RAS segments which
operate (documentation for compliance with Requirement R5 Part 5.1). If an event causes
a partial operation of a RAS, the segments without an operation will require a separate
functional test within the maximum interval with the starting date determined by the
previous successful test of the segments that did not operate.
R8.
Each RAS‐entity shall participate in performing a functional test of each of its RAS to
verify the overall RAS performance and the proper operation of non‐Protection
System components: [Violation Risk Factor: High] [Time Horizon: Long‐term Planning]
At least once every six full calendar years for all RAS not designated as limited
impact, or
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis for a correct RAS segment or an end‐to‐end
operation (Measure M5 documentation), or dated documentation demonstrating that
a functional test of each RAS segment or an end‐to‐end test was performed in
accordance with Requirement R8.
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PRC‐012‐2 – Remedial Action Schemes
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high‐level information on existing RAS that could potentially impact the
operational and/or planning activities of that entity. Attachment 3 lists the minimum
information required for the RAS database, which includes a summary of the RAS
initiating conditions, corrective actions, and System issues being mitigated. This
information allows an entity to evaluate the reliability need for requesting more detailed
information from the RAS‐entities identified in the database contact information. The RC
is the appropriate entity to maintain the database because the RC receives the required
database information when a new or modified RAS is submitted for review. The twelve
full calendar month time frame is aligned with industry practice and allows sufficient time
for the RC to collect the appropriate information from RAS‐entities and update the RAS
database.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS‐entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1, R3, R5, R6, R7, and R8, and Measures M1, M3, M5, M6, M7,
and M8 since the last audit, unless directed by its Compliance Enforcement
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PRC‐012‐2 – Remedial Action Schemes
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M2 and M9 since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS‐entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non‐compliant, it shall
keep information related to the non‐compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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PRC‐012‐2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS‐entity failed to
provide the information
identified in Attachment 1 to
each Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30 full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90 full
calendar days.
Draft 3 of PRC‐012‐2
February 2016
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
Page 14 of 50
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS‐entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
R4.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 90 full
calendar days.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate two or more of
the Parts 4.1.1 through 4.1.5.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1.1 through 4.1.5.
Draft 3 of PRC‐012‐2
February 2016
OR
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
R5.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by less than or
equal to 10 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 30 full
calendar days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to address two or
more of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to address one of the
Parts 5.1.1 through 5.1.4.
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February 2016
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
(Part 5.2) to one or more of
the reviewing Reliability
Coordinator(s).
OR
The RAS‐entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10 full calendar days.
Draft 3 of PRC‐012‐2
February 2016
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30 full
calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but
failed to submit it to one or
Page 17 of 50
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
more of its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6.
OR
The RAS‐entity failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS‐entity implemented N/A
a CAP in accordance with
Requirement R7, Part 7.1,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed, or failed
to notify (Part 7.3) each of
the reviewing Reliability
Coordinator(s) of the
updated CAP or completion
of the CAP.
N/A
The RAS‐entity failed to
implement a CAP in
accordance with
Requirement R7, Part 7.1.
R8.
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by less than
or equal to 30 full calendar
days.
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 60 full calendar days
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 90 full calendar days.
Draft 3 of PRC‐012‐2
February 2016
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 30 full calendar days
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
R9.
Moderate VSL
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30 full calendar days.
Draft 3 of PRC‐012‐2
February 2016
High VSL
Severe VSL
but less than or equal to 60
full calendar days.
but less than or equal to 90
full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
OR
The RAS‐entity failed to
perform the functional test
for a RAS as specified in
Requirement R8.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90 full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
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PRC‐012‐2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
Date
Action
Change Tracking
1
Adopted by NERC Board of Trustees
New
Draft 3 of PRC‐012‐2
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Page 20 of 50
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified2 RAS that the RAS‐entity must document and provide to
the reviewing Reliability Coordinator(s) (RC). If an item on this list does not apply to a
specific RAS, a response of “Not Applicable” for that item is appropriate. When RAS are
submitted for functional modification review and approval, only the proposed modifications
to that RAS require review; however, the RAS‐entity must provide a summary of the existing
functionality. The RC may request additional information on any aspect of the RAS as well as
any reliability issue related to the RAS. Additional entities (without decision authority) may
be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐
voltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
2
f. Action(s) to be taken by the RAS.
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
Draft 3 of PRC‐012‐2
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Attachments
g. Identification of limited impact3 RAS.
h. Any additional explanation relevant to high‐level understanding of the RAS.
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS‐entity proposal and justification for limited impact designation, if applicable.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
8. Identification of other affected RCs.
3
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations.
Draft 3 of PRC‐012‐2
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Attachments
III. Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in‐service or is being
maintained.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective.
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS‐entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability‐related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any aspect of the RAS as well as any reliability issue related to the RAS. If a
checklist item is not relevant to a particular RAS, it should be noted as “Not Applicable.” If
reliability considerations are identified during the review, the considerations and the proposed
resolutions should be documented with the remaining applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The designed timing of RAS operation(s) is appropriate to its BES performance
objectives.
3. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
4. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
5. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate, have been identified.
6. Determination whether or not the RAS is limited impact.5 A RAS designated as limited
impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations.
7. Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
4
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
5
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations.
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Attachments
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
8. The effects of future BES modifications on the design and operation of the RAS have
been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. Except for limited impact RAS as determined by the RC, a single component failure in a
RAS does not prevent the BES from meeting the same performance requirements as
those required for the events and conditions for which the RAS is designed.
3. The RAS design facilitates periodic testing and maintenance.
4. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
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Attachments
Attachment 3
Database Information
1. RAS name.
2. Each RAS‐entity and contact information.
3. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact6 RAS.
8. Any additional explanation relevant to high‐level understanding of the RAS.
6
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations.
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Supplemental Material
Technical Justification
4.1.1 Reliability Coordinator
The Reliability Coordinator (RC) is the best‐suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest‐area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide‐
Area purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best‐suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS‐entity
The RAS‐entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RAS‐
entity has sole responsibility for all the activities assigned within the standard to the RAS‐entity.
If the RAS (RAS components) have more than one owner, then each separate RAS component
owner is a RAS‐entity and is obligated to participate in various activities identified by the
Requirements.
The standard does not stipulate particular compliance methods. RAS‐entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS‐entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS‐entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Limited impact
RAS are unique and customized assemblages of protection and control equipment that vary in
complexity and impact on the reliability of the BES. These differences in RAS design, action, and
risk to the BES are identified and verified within the construct of Requirements R1‐R4 of PRC‐
012‐2.
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Supplemental Material
The reviewing RC has the authority to designate a RAS as limited impact if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The reviewing RC is the sole arbiter for determining whether a RAS qualifies for the
limited impact designation. The limited impact designation is available to any RAS in any Region
provided the reviewing RC determines the RAS poses a low risk to BES reliability.
The limited impact designation is modeled after the Local Area Protection Scheme (LAPS)
classification in WECC (Western Electricity Coordinating Council) and the Type 3 classification in
NPCC (Northeast Power Coordinating Council). The following information describing the
aforementioned WECC and NPCC RAS is excerpted from the respective regional
documentation7.The drafting team notes that the information below represents the state of the
WECC and NPCC regional processes at the time of this standard development and is subject to
change before the effective date of PRC‐012‐2.
WECC: Local Area Protection Scheme (LAPS)
A Remedial Action Scheme (RAS) whose failure to operate would NOT result in any of the
following:
•
•
•
Violations of TPL‐001‐WECC‐RBP System Performance RBP,
Maximum load loss ≥ 300 MW,
Maximum generation loss ≥ 1000 MW.
NPCC: Type III
An SPS whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for
classification:
Significant adverse impact – With due regard for the maximum operating capability of the
affected systems, one or more of the following conditions arising from faults or disturbances,
shall be deemed as having significant adverse impact:
a. system instability;
b. unacceptable system dynamic response or equipment tripping;
c. voltage levels in violation of applicable emergency limits;
d. loadings on transmission facilities in violation of applicable emergency limits;
e. unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and
number of system elements contained will vary based on system characteristics. A local area
may be relatively large geographically with relatively few buses in a sparse system, or be
7
WECC Procedure to Submit a RAS for Assessment Information Required to Assess the Reliability of a RAS
Guideline, Revised 10/28/2013 | NPCC Regional Reliability Reference Directory # 7, Special Protection Systems,
Version 2, 3/31/2015
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Supplemental Material
relatively small geographically with a relatively large number of buses in a densely
networked system.
Because the drafting team modeled the limited impact designation after the WECC and NPCC
classifications, each RAS implemented prior to the effective date of PRC‐012‐2 that has been
through the regional review processes of WECC or NPCC and classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3 in NPCC, is recognized as a limited impact RAS
upon the effective date of PRC‐012‐2 and is subject to all applicable requirements.
To propose an existing RAS (a RAS implemented prior to the effective date of PRC‐012‐2) be
designated as limited impact by the reviewing RC, the RAS‐entity must prepare and submit the
appropriate Attachment 1 information that includes the technical justification (evaluations)
documenting that the System can meet the performance requirements (specified in
Requirement R4, Parts 4.1.4 and 4.1.5) resulting from a single RAS component malfunction or
failure, respectively.
There is nothing that precludes a RAS‐entity from working with the reviewing RC during the
implementation period of PRC‐012‐2, in anticipation of the standard becoming enforceable.
However, even if the reviewing RC determines the RAS qualifies as limited impact, the
designation is not relevant until the standard becomes effective. Until then, the existing
regional processes remain in effect as well as the existing RAS classifications or lack thereof.
An example of a scheme that could be recognized as a limited impact RAS is a load shedding or
generation rejection scheme used to mitigate the overload of a BES transmission line. The
inadvertent operation of such a scheme would cause the loss of either a certain amount of
generation or load. The evaluation by the RAS‐entity should demonstrate that the loss of this
amount of generation or load, without the associated contingency for RAS operation actually
occurring, is acceptable and not detrimental to the reliability of BES; e.g., in terms of frequency
and voltage stability. The failure of that scheme to operate when intended could potentially
lead to the overloading of a transmission line beyond its acceptable rating. The RAS‐entity
would need to demonstrate that this overload, while in excess of the applicable Facility Rating,
is not detrimental to the BES outside the contained area (predetermined by studies) affected by
the contingency.
Another example of a limited‐impact RAS is a scheme used to protect BES equipment from
damage caused by overvoltage through generation rejection or equipment tripping.
Another example of a limited‐impact RAS is a centrally‐controlled undervoltage load shedding
scheme used to protect a contained area (predetermined by studies) of the BES against voltage
collapse.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
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Supplemental Material
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Functional modifications consists of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original
functionality of existing components
Changes to RAS logic beyond correcting existing errors
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in‐kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that uses similar
functions. For instance, if a RAS included a CO‐11 relay which was replaced by an IAC‐53 relay,
that would be an in‐kind replacement. If the CO‐11 relay were replaced by a microprocessor
SEL‐451 relay that used only the same functions as the original CO‐11 relay, that would also be
an in‐kind replacement; however, if the SEL‐451 relay was used to add new logic to what the
CO‐11 relay had provided, then the replacement relay would be a functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. For example, System conditions require a RAS to be armed when the
combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to Requirement
R4, or other assessment, indicates that the arming level should be reduced to 450 MW without
requiring any other RAS changes that would not be a functional modification. Similarly, if a RAS
is designed to shed load to reduce loading on a particular line below 1000 amps, then a change
in the load shedding trigger from 1000 amps to 1100 amps would not be a functional
modification.
Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs to the RAS) and the logic to recognize the specific line outages would
change, while the generation reduction (RAS output) requirement may or may not change,
depending on which line is out of service. These required RAS changes would be a functional
modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for such functional modifications
may be identified in several ways including but not limited to the Planning evaluations pursuant
to R4, incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning
assessments related to future additions or modifications of other facilities.
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To facilitate a review that promotes reliability, the RAS‐entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS‐entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS‐entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RAS‐
entity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS‐entity(ies). An independent review by a multi‐disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the
widest‐area reliability perspective of all functional entities and an awareness of reliability issues
in neighboring RC Areas. This Wide Area purview facilitates the evaluation of interactions
among separate RAS as well as interactions among the RAS and other protection and control
systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS‐entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement. It is recognized that the RC does not
possesses more information or ability than anticipated by their functional registration as
designated by NERC. The NERC Functional Model is a guideline for the development of
standards and their applicability and does not contain compliance requirements. If Reliability
Standards address functions that are not described in the model, the Reliability Standard
requirements take precedence over the Functional Model. For further reference, please see the
Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
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Supplemental Material
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
for review. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
Requirement R3
Requirement R3 mandates that each RAS‐entity resolve all reliability issues (pertaining to its
RAS) identified during the RAS review by the reviewing Reliability Coordinators. Examples of
reliability issues include a lack of dependability, security, or coordination. RC approval of a RAS
is considered to be obtained when the reviewing RC’s feedback to each RAS‐entity indicates
that either no reliability issues were identified during the review or all identified reliability
issues were resolved to the RC’s satisfaction.
Dependability is a component of reliability that is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over‐tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability that is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re‐configuring the System. Such actions, if inadvertently taken, are undesirable
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC‐
012‐2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS‐entity or the reviewing RC(s) may
have alternative ideas or methods available to resolve the issue(s). In either case, the concern
needs to be resolved in deference to reliability, and the RC has the final decision.
A specific time period for the RAS‐entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS‐entity to effect a timely
implementation.
A specific time period for the RC to respond to the RAS‐entity following the RAS review is also
not necessary because the RC will be aware of (1) any reliability issues associated with the RAS
not being in service and (2) the RAS‐entity’s schedule to implement the RAS to address those
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Supplemental Material
reliability issues. Since the RC is the ultimate arbiter of BES operating reliability, resolving
reliability issues is a priority for the RC and serves as an incentive to expeditiously respond to
the RAS‐entity.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every five
full calendar years. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it interacts with and impacts the
BES.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate,
cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations. Limited impact RAS are not
subject to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to the
design with minimal benefit to BES reliability.
A RAS implemented after the effective date of this standard can only be designated as limited
impact by the reviewing RC(s). A RAS implemented prior to the effective date of PRC‐012‐2 that
has been through the regional review processes of WECC or NPCC and is classified as either a
Local Area Protection Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited
impact RAS upon the effective date of PRC‐012‐2 for the purposes of this standard and is
subject to all applicable requirements.
Requirement R4 also clarifies that the RAS single component failure and inadvertent operation
tests do not apply to RAS which are determined to be limited impact. Requiring a limited impact
RAS to meet the single component failure and inadvertent operation tests would just add
complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within five full
calendar years of the effective date of PRC‐012‐2. For new or functionally modified RAS, the
initial performance of the requirement must be completed within five full calendar years of the
RAS approval date by the reviewing RC(s). Five full calendar years was selected as the maximum
time frame between evaluations based on the time frames for similar requirements in
Reliability Standards PRC‐006, PRC‐010, and PRC‐014. The RAS evaluation can be performed
sooner if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. System
changes also have the potential to alter the reliability impact of limited impact RAS on the BES.
Requirement 4, Part 4.1.3 explicitly requires the periodic evaluation of limited impact RAS to
verify the limited impact designation remains applicable. The periodic RAS evaluation will
typically lead to one of the following outcomes: 1) affirmation that the existing RAS is effective;
2) identification of changes needed to the existing RAS; or, 3) justification for RAS retirement.
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The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.5) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The PC is the functional entity best suited to perform the
analyses because they have a wide‐area planning perspective. To promote reliability, the PC is
required to provide the results of the evaluation to each impacted Transmission Planner and
Planning Coordinator, in addition to each reviewing RC and RAS‐entity. In cases where a RAS
crosses PC boundaries, each affected PC is responsible for conducting either individual
evaluations or participating in a coordinated evaluation.
The intent of Requirement R4, Part 4.1.4 is to require that the possible inadvertent operation of
the RAS (other than limited impact RAS), caused by the malfunction of a single component of
the RAS, meet the same System performance requirements as those required for the
Contingency(ies) or System conditions for which it is designed. If the RAS is designed to meet
one of the planning events (P0‐P7) in TPL‐001‐4, the possible inadvertent operation of the RAS
must meet the same performance requirements listed in the standard for that planning event.
The requirement clarifies that the inadvertent operation to be considered is only that caused by
the malfunction of a single RAS component. This allows features to be designed into the RAS to
improve security, such that inadvertent operation due to malfunction of a single component is
prevented; otherwise, the RAS inadvertent operation must satisfy Requirement R4, Part 4.1.4.
The intent of Requirement R4, Part 4.1.4 is also to require that the possible inadvertent
operation of the RAS (other than limited impact RAS) installed for an extreme event in TPL‐001‐
4 or for some other Contingency or System conditions not defined in TPL‐001‐4 (therefore
without performance requirements), meet the minimum System performance requirements of
Category P7 in Table 1 of NERC Reliability Standard TPL‐001‐4. However, instead of referring to
the TPL standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.4.1 – 4.1.4.5) are the ones that are common to all planning events (P0‐P7) listed in
TPL‐001‐4.
With reference to Requirement 4, Part 4.1.4, note that the only differences in performance
requirements among the TPL (P0‐P7) events (not common to all of them) concern Non‐
Consequential Load Loss and interruption of Firm Transmission Service. It is not necessary for
Requirement R4, Part 4.1.4 to specify performance requirements related to these areas
because a RAS is only allowed to drop non‐consequential load or interrupt Firm Transmission
Service if that action is allowed for the Contingency for which it is designed. Therefore, the
inadvertent operation should automatically meet Non‐Consequential Load Loss or interrupting
Firm Transmission Service performance requirements for the Contingency(ies) for which it was
designed.
Part 4.1.5 requires that a single component failure in the RAS (other than limited impact RAS),
when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. This analysis is needed to
ensure that changing System conditions do not result in the single component failure
requirement not being met.
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Supplemental Material
Requirements for inadvertent RAS operation (Requirement R4, Part 4.1.4) and single
component failure (Requirement R4, Part 4.1.5) are reviewed by the reviewing RC(s) before a
new or functionally modified RAS is placed in‐service, and are typically satisfied by specific
design considerations. Although the scope of the periodic evaluation does not include a new
design review, it is possible that a design which previously satisfied requirements for
inadvertent RAS operation and single component failure may fail to satisfy these requirements
at a later time, and must be evaluated with respect to the current System. For example, if the
actions of a particular RAS include tripping load, load growth could occur over time that impacts
the amount of load to be tripped. These changes could result in tripping too much load upon
inadvertent operation and result in violations of Facility Ratings. Alternatively, the RAS might be
designed to trip more load than necessary (i.e., “over trip”) in order to satisfy single component
failure requirements. System changes could result in too little load being tripped and
unacceptable BES performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4 regarding
the investigation of a Protection System Misoperation; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
the RAS‐entity(s) is required to provide the results of RAS operational performance analyses to
its reviewing RC(s) if the analyses revealed a deficiency.
The RAS‐entity(ies) may need to collaborate with its associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS‐entity for a RAS, the RAS‐entities would collaborate to conduct and
submit a single, coordinated operational performance analysis.
Requirement R6
RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may be identified
in the periodic RAS evaluation conducted by the PC in Requirement R4, in the operational
analysis conducted by the RAS‐entity in Requirement R5, or in the functional test performed by
the RAS‐entity(ies) in Requirement R8. To mitigate potential reliability risks, Requirement R6
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mandates that each RAS‐entity participate in developing a CAP that establishes the mitigation
actions and timetable necessary to address the deficiency.
The RAS‐entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS‐entity(ies) may request assistance with development of the
CAP from other parties such as its Transmission Planner or Planning Coordinator; however, the
RAS‐entity has the responsibility for compliance with this requirement.
A CAP may require functional changes be made to a RAS. In this case, Attachment 1 information
must be submitted to the reviewing RC(s), an RC review must be performed to obtain RC
approval before the RAS‐entity can place RAS modifications in‐service, per Requirements R1,
R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering or consulting work. A timeframe of six full calendar months is allotted to allow
enough time for RAS‐entity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. Ideally, when there is more than one RAS‐
entity for a RAS, the RAS‐entities would collaborate to develop and submit a single, coordinated
CAP. A RAS deficiency may require the RC or Transmission Operator to impose operating
restrictions so the System can operate in a reliable way until the RAS deficiency is resolved. The
possibility of such operating restrictions will incent the RAS‐entity to resolve the issue as quickly
as possible.
The following are example situations of when a CAP is required:
A determination after a RAS operation/non‐operation investigation that the RAS did not
meet performance expectations or did not operate as designed.
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
Equipment failures.
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
Requirement R7 mandates that each RAS‐entity implement its CAP developed in Requirement
R6 which mitigates the deficiencies identified in Requirements R4, R5, or R8. By definition, a
CAP is: “A list of actions and an associated timetable for implementation to remedy a specific
problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. If the CAP is changed, the RAS‐entity must notify the reviewing Reliability
Coordinator(s). The RAS‐entity must also notify the Reliability Coordinator(s) when the CAP has
been completed.
The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
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operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS‐entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non‐Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in‐service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC‐005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed with minimum impact to the
BES and should align with expected results. The RAS‐entity is in the best position to determine
the testing procedure and schedule due to their overall knowledge of the RAS design,
installation, and functionality. Periodic testing provides the RAS‐entity assurance that latent
failures may be identified and also promotes identification of changes in the System that may
have introduced latent failures.
The six and twelve full calendar year functional testing intervals are greater than the annual or
bi‐annual periodic testing performed in some NERC Regions. However, these intervals are a
balance between the resources required to perform the testing and the potential reliability
impacts to the BES created by undiscovered latent failures that could cause an incorrect
operation of the RAS. Longer test intervals for limited impact RAS are acceptable because
incorrect operations or failures to operate present a low reliability risk to the Bulk Power
System.
Functional testing is not synonymous with end‐to‐end testing. End‐to‐end testing is an
acceptable method but may not be feasible for many RAS. When end‐to‐end testing is not
possible, a RAS‐entity may use a segmented functional testing approach. The segments can be
tested individually negating the need for complex maintenance schedules. In addition, actual
RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does not
operate in its entirety during a System event or System conditions do not allow an end‐to‐end
scheme test, then the segmented approach should be used to fulfill this Requirement.
Functional testing includes the testing of all RAS inputs used for detection, arming, operating,
and data collection. Functional testing, by default operates the processing logic and
infrastructure of a RAS, but focuses on the RAS inputs as well as the actions initiated by RAS
outputs to address the System condition(s) for which the RAS is designed. All segments and
components of a RAS must be tested or have proven operations within the applicable
maximum test interval to demonstrate compliance with the Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
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functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC‐005, Table 1‐1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up‐to the protective
relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3‐8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well‐defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component‐level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of Contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real‐time) to
the Transmission Operator via PRC‐001, Requirement R6, then to the RC via TOP‐001‐3,
Requirement R8. See Phase 2 of Project 2007‐06 for the mapping document from PRC‐001 to
other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end‐to‐end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS‐entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
maximum test interval that started on the date of the previous successful test of those (non‐
operating) segments in order to be compliant with Requirement R8.
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Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available. Attachment 3 contains the minimum information that is
required to be included about each RAS listed in the database. Additional information can be
requested by the RC.
The database enables the RC to provide other entities high‐level information on existing RAS
that could potentially impact the operational and/or planning activities of that entity. The
information provided is sufficient for an entity with a reliability need to evaluate whether the
RAS can impact its System. For example, a RAS performing generation rejection to mitigate an
overload on a transmission line may cause a power flow change within an adjacent entity area.
This entity should be able to evaluate the risk that a RAS poses to its System from the high‐level
information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS‐entity from the RC.
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Process Flow Diagram
The diagram below depicts the process flow of the PRC‐012‐2 requirements.
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS‐entity(ies) to provide a detailed list of information
describing the RAS to the reviewing RC. If there are multiple RAS‐entities for a single RAS,
information will be needed from all RAS‐entities. Ideally, in such cases, a single RAS‐entity will
take the lead to compile all the data identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide‐ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified8 RAS that the RAS‐entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS‐entity
provides a summary of the existing RAS functionality.
I.
General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single‐line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012‐2, Requirements R5 and R7]
8
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
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Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name.
b. Each RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date;
most recent five full calendar year (Requirement R4) evaluation date; and, date of
retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (initiating conditions).
f. Corrective action taken by the RAS.
g. Identification of limited impact9 RAS.
h. Any additional explanation relevant to high level understanding of the RAS.
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical System
Contingencies or other operating conditions when RAS action is intended to occur.
If no arming conditions are required, this should also be stated.
c. Event‐based RAS are triggered by specific Contingencies that initiate mitigating
action. Condition‐based RAS may also be initiated by specific Contingencies, but
9
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations.
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specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed. [Reference NEC Reliability Standard PRC‐014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS‐related operations.
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. RAS‐entity proposal and justification for limited impact designation, if applicable.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of PRC‐012‐2 that has been through the
regional review processes of WECC or NPCC and is classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited impact
RAS upon the effective date of PRC‐012‐2 for the purposes of this standard and is
subject to all applicable requirements.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
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b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or re‐
configuring the System. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available fault duty,
which can affect distance relay overcurrent (“fault detector”) supervision and ground
overcurrent protection coordination.
8. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be
designed to be secure. Several types of devices have been commonly used as disturbance,
condition, or status detectors:
Line open status (event detectors),
Protective relay inputs and outputs (event and parameter detectors),
Transducer and IED (analog) inputs (parameter and response detectors),
Rate of change (parameter and response detectors).
DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by
PRC‐005. However, redundant RAS systems, when used, should be supplied from
separately protected (fused or breakered) circuits.
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Communications: Telecommunications Channels
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non‐deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel
or equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS‐entity, or
perhaps leased from another entity familiar with the necessary reliability requirements.
All channel equipment should be monitored and alarmed to the dispatch center so that
timely diagnostic and repair action shall take place upon failure. Publicly switched
telephone networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel
working on the channel can readily identify the proper circuit. Channels between entities
should be identified with a common name at all terminals.
Transfer Trip
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions
may be required at different arming levels or for different Contingencies. Scheme logic
may be achievable by something as simple as wiring a few auxiliary relay contacts or by
much more complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units
(RTUs), and logic processors. Single‐function relays have been used historically to
implement RAS, but this approach is now less common except for very simple new RAS or
minor additions to existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS
actions at the sites where action is required.
Monitoring by SCADA/EMS should include at least
Whether the scheme is in‐service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in‐service or out of service.
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For RAS that are armed automatically, these two states are independent because
a RAS that has been placed in‐service may be armed or unarmed based on
whether the automatic arming criteria have been met.
The current operational state of the scheme (available or not).
In cases where the RAS requires single component failure performance; e.g.,
redundancy, the minimal status indications should be provided separately for each
system.
The minimum status is generally sufficient for operational purposes; however,
where possible it is often useful to provide additional information regarding
partial failures or the status of critical components to allow the RAS‐entity to
more efficiently troubleshoot a reported failure. Whether this capability exists
will depend in part on the design and vintage of equipment used in the RAS.
While all schemes should provide the minimum level of monitoring, new
schemes should be designed with the objective of providing monitoring at least
similar to what is provided for microprocessor‐based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line‐charging current;
c. Breaker trip coil current monitoring—typically used when high‐speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of the
aforementioned, out of step, etc. are dependent on specific scheme requirements,
but some forms may substitute for or enhance other monitoring described in items
‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in‐service or is being
maintained.
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In this context, a multifunction device (e.g., microprocessor‐based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor‐based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi‐function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective. [Reference NERC Reliability Standard PRC‐012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement. Acceptable methods to achieve this objective
include, but are not limited to the following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
Protective or auxiliary relays used by the RAS.
ii.
Communications systems necessary for correct operation of the RAS.
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iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation due to that single component failure will still result in
satisfactory System performance, as long as tripping the total armed amount of load
or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re‐dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS‐entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies and technical justifications, if applicable, upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent‐wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability‐related considerations relevant to various aspects of RAS design and
implementation.
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
The name used to identify the RAS.
2. Each RAS‐entity and contact information.
A reliable phone number or email address should be included to contact each RAS‐entity
if more information is needed.
3. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date; most
recent five full calendar year (Requirement R4) evaluation date; and, date of retirement, if
applicable.
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under‐/over‐voltage, slow voltage
recovery).
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the Contingencies or System conditions for which the RAS was designed
(initiating conditions).
A high level summary of the conditions/Contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
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7. Identification of limited impact10 RAS.
Specify whether or not the RAS is designated as limited impact.
8. Any additional explanation relevant to high‐level understanding of the RAS.
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
10
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations.
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PRC‐012‐2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 2 of PRC‐012‐2 corrects the applicability of the fill‐in‐the‐blank standards (PRC‐012‐1,
PRC‐013‐1, and PRC‐014‐1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk‐Power System, and incorporates the reliability objectives of
all the RAS/SPS‐related standards. This draft contains nine requirements and measures, the
associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. This draft of PRC‐012‐2 is posted for a 45‐day formal comment period with a
parallel ballot in the last ten days of the comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC‐012‐2 posted for informal comment
April 30 – May 20, 2015
45‐day formal comment period with initial ballot
August 20 – October 5,
2015
45‐day formal comment period with additional ballot
November 25, 2015 –
January 8, 2016
45‐day formal comment period with additional ballot
February 3, 2016 –
March 18, 2016
Anticipated Actions
Date
10‐day final ballot
MarchApril 2016
NERC Board (Board) adoption
May 2016
Draft 23 of PRC‐012‐2
November 2015February 2016
Page 1 of 55
PRC‐012‐2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
3.
Number:
Purpose:
PRC‐012‐2
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Planning Coordinator
4.1.3. RAS‐entity – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC‐012‐2.
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PRC‐012‐2 – Remedial Action Schemes
B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement; i.e., removal from service must be completed prior
to implementation or retirement.
Functional modifications consist of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original
functionality of existing components
Changes to RAS logic beyond error correcting existing errors
Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS‐entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS‐entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. Ideally, when there is more than one RAS‐entity for
a RAS, the RAS‐entities would collaborate and submit a single, coordinated Attachment 1
to the reviewing RC. In cases where a RAS crosses one or more RC Area boundaries, each
affected RC is responsible for conducting either individual reviews or participating in a
coordinated review.
R1.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest‐area operational and reliability perspective of all
functional entities and an awareness of reliability issues in any neighboring RC Area. This
Wide Area purview facilitates the evaluation of interactions among separate RAS as well
as interactions among RAS and other protection and control systems. Review by the RC
also minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP),
or other entities that are likely to be involved in the planning or implementation of a RAS.
The RC is not expected to possess more information or ability than anticipated by their
Draft 23 of PRC‐012‐2
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PRC‐012‐2 – Remedial Action Schemes
functional registration as designated by NERC. The RC may request assistance to perform
RAS reviews from other parties such as the PC or regional technical groups; however, the
RC will retain the responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each submitted RAS.
The time frame of four full calendar months is consistent with current utility and regional
practice; however, flexibility is provided by allowing the RC(s) and RAS‐entity(ies) to
negotiate a mutually agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to each RAS‐entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS‐entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in‐service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS‐entity to respond to the reviewing RC following
identification of any reliability issue(s) is not necessary because the RAS‐entity wants to
expedite the timely approval and subsequent implementation of the RAS.
A specific time period for the RC to respond to the RAS‐entity following the RAS review is
also not necessary because the RC will be aware of (1) any reliability issues associated
with the RAS not being in service and (2) the RAS‐entity’s schedule to implement the RAS
to address those reliability issues. Since the RC is the ultimate arbiter of BES operating
reliability, resolving reliability issues is a priority for the RC and serves as an incentive to
expeditiously respond to the RAS‐entity.
R3.
Prior to placing a new or functionally modified RAS in‐service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability Coordinator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
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PRC‐012‐2 – Remedial Action Schemes
were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every sixtyfive full calendar monthsyears. The purpose of the
periodic RAS evaluation is to verify the continued effectiveness and coordination of the
RAS, as well as to verify that, if a RAS single component failuremalfunction or single
component malfunctionfailure were to occur, the requirements for BES performance
would continue to be satisfied. TheA periodic evaluation is neededrequired because
changes in System topology or operating conditions may change the effectiveness of a
RAS or the way it impacts the BES. Requirement R4 also clarifies
RAS are unique and customized assemblages of protection and control equipment that
vary in complexity and impact on the RAS single component failure and single component
malfunction tests do not apply toreliability of the BES. In recognition of these differences,
RAS which are determined tocan be limited impact. A RAS designated by the reviewing
RC(s) as limited impact. A limited impact RAS cannot, by inadvertent operation or failure
to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented after the effective date of this standard will be designated as
limitedLimited impact orRAS are not by the reviewing RC(s) during its review. A RAS
implemented priorsubject to the effective date of this standard that has been through the
regional review process RAS single component malfunction and designated as Type 3 in
NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact for the
purposes of Requirement 4, failure tests of Parts 4.1.34 and 4.1.4.5, respectively.
Requiring a limited impact RAS to meet the single component failure and single
component malfunction these tests would add complexity to the design with minimal
benefit to theBES reliability of the BES. See Attachment 2the Supplemental Material for a
description ofmore on the limited impact determination by the Reliability
Coordinatordesignation.
The limited impact designation is modeled after the Local Area Protection Scheme (LAPS)
classification in WECC (Western Electricity Coordinating Council) and the Type 3
classification in NPCC (Northeast Power Coordinating Council). A RAS implemented prior
to the effective date of PRC‐012‐2 that has been through the regional review processes of
WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC
or a Type 3 in NPCC is recognized as a limited impact RAS upon the effective date of PRC‐
012‐2 for the purposes of this standard and is subject to all applicable requirements.
For existing RAS, the initial performance of Requirement R4 must be completed within
sixtyfive full calendar monthsyears of the effective date of PRC‐012‐2. For new or
functionally modified RAS, the initial performance of the requirement must be completed
within sixtyfive full calendar monthsyears of the RAS approval date by the reviewing
RC(s). SixtyFive full calendar monthsyears was selected as the maximum time frame
between evaluations based on the time frames for similar requirements in Reliability
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PRC‐012‐2 – Remedial Action Schemes
Standards PRC‐006, PRC‐010, and PRC‐014. The RAS evaluation can be performed sooner
if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. System
changes also have the potential to alter the reliability impact of limited impact RAS on the
BES. Requirement 4, Part 4.1.3 explicitly requires the periodic evaluation of limited
impact RAS to verify the limited impact designation remains applicable. The periodic RAS
evaluation will typically lead to one of the following outcomes: 1) affirmation that the
existing RAS is effective; 2) identification of changes needed to the existing RAS; or, 3)
justification for RAS retirement.
The items required to be addressed in the evaluationevaluations (Requirement R4, Parts
4.1.1 through 4.1.5) are planning analyses that may involve modeling of the
interconnected transmission system to assess BES performance. The Planning
Coordinator (PC) is the functional entity best suited to perform this evaluation because
they have a wide area planning perspective. To promote reliability, the PC is required to
provide the results of the evaluation to each impacted Transmission Planner and Planning
Coordinator, in addition to each reviewing RC and RAS‐entity. In cases where a RAS
crosses PC boundaries, each affected PC is responsible for conducting either individual
evaluations or participating in a coordinated evaluation.
The previous version of this standard (PRC‐012‐1 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL‐001‐
0, TPL‐002‐0, and TPL‐003‐0) as that required of the Contingency for which it was
designed, and not exceed TPL‐003‐0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise,
consistent with PRC‐012‐1 Requirement 1, R1.4, the RAS should be designed so that its
whole or partial inadvertent operation due to a single component malfunction satisfies
the System performance requirements for the same Contingency for which the RAS was
designed.
If the RAS was installed for an extreme event in TPL‐001‐4 or for some other Contingency
or System condition not defined in TPL‐001‐4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL‐001‐4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.1.3.1 – 4.1.3.5) are the ones that
are common to all planning events P0‐P7 listed in TPL‐001‐4.
R4.
Each Planning Coordinator, at least once every 60five full calendar monthsyears, shall:
[Violation Risk Factor: Medium] [Time Horizon: Long‐term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
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4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for which
it was designed.
4.1.2. The RAS avoids adverse interactions with other RAS, and protection and
control systems.
4.1.3. For limited impact1 RAS, the inadvertent operation of the RAS or the
failure of the RAS to operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations.
4.1.3.4.1.4. Except for limited impact RAS, the possible inadvertent operation
of the RAS, resulting from any single RAS component malfunction
satisfies all of the following:
4.1.3.1.4.1.4.1.
The BES shall remain stable.
4.1.3.2.4.1.4.2.
Cascading shall not occur.
4.1.3.3.4.1.4.3.
Applicable Facility Ratings shall not be exceeded.
4.1.3.4.4.1.4.4.
BES voltages shall be within post‐Contingency
voltage limits and post‐Contingency voltage deviation limits as
established by the Transmission Planner and the Planning
Coordinator.
4.1.3.5.4.1.4.5.
Transient voltage responses shall be within
acceptable limits as established by the Transmission Planner
and the Planning Coordinator.
4.1.4.4.1.5. Except for limited impact RAS, a single component failure in the
RAS, when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS‐entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS‐entity(ies), Transmission Planner(s), Planning
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact for the purposes of Requirement 4, Parts 4.1.3 and 4.1.4.
1
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Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
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Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation was
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4
regarding the investigation of a Protection System Misoperation. To promote reliability,
each RAS‐entity is required to provide the results of RAS operational performance
analyses that identified any deficiencies to its reviewing RC(s).
RAS‐entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly
(Part 5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response
(Parts 5.1.3 and 5.1.4) was consistent with the intended functionality and design of the
RAS. Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would
collaborate on theto conduct and submit a single, coordinated operational performance
analysis.
R5.
Each RAS‐entity, within 120 full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.1. The System events and/or conditions appropriately triggered the RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with participating RAS‐entities and the reviewing Reliability Coordinator(s) in
accordance with Requirement R5.
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Rationale for Requirement R6: Deficiencies identified in the periodic RAS evaluation
conducted by the PC pursuant to Requirement R4, in the operational performance
analysis conducted by the RAS‐entity pursuant to Requirement R5, or in the functional
test performed by the RAS‐entity pursuant to Requirement R8, potentially pose a
reliability risk to the BES. To mitigate these potential reliability risks, Requirement R6
mandates that each RAS‐entity develop a Corrective Action Plan (CAP) to address the
identified deficiency. The CAP contains the mitigation actions and associated timetable
necessary to remedy the specific deficiency. The RAS‐entity may request assistance with
CAP development from other parties such as its Transmission Planner or Planning
Coordinator; however, the RAS‐entity has the responsibility for compliance with this
requirement.
If the CAP requires that a functional change be made to a RAS, the RAS‐entity will need to
submit information identified in Attachment 1 to the reviewing RC(s) prior to placing RAS
modifications in‐service per Requirement R1.
Depending on the complexity of the identified deficiency(ies), development of a CAP may
require studies, and other engineering or consulting work. A maximum time frame of six
full calendar months is specified for RAS‐entity collaboration on the CAP development.
Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would
collaborate to develop and submit a single, coordinated CAP.
R6.
Each RAS‐entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐
term Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency pursuant to Requirements
R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS‐entity in
accordance with Requirement R6.
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PRC‐012‐2 – Remedial Action Schemes
Rationale for Requirement R7: Requirement R7 mandates each RAS‐entity implement a
CAP (developed in Requirement R6) that mitigates the deficiencies identified in
Requirements R4, R5, or R8. By definition, a CAP is: “A list of actions and an associated
timetable for implementation to remedy a specific problem.” The implementation of a
properly developed CAP ensures that RAS deficiencies are mitigated in a timely manner.
Each reviewing Reliability Coordinator must be notified if CAP actions or timetables
change, and when the CAP is completed.
R7.
Each RAS‐entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long‐term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the reviewing Reliability
Coordinator(s) that documents the implementation, updating, or completion of a CAP
in accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non‐Protection System (control) components of a RAS that are not addressed in PRC‐005.
Protection System components that are part of a RAS are maintained in accordance with
PRC‐005.
The six or twelve full calendar year test interval, which begins on the effective date of the
standard pursuant to the PRC‐012‐2 implementation plan, is a balance between the
resources required to perform the testing and the potential reliability impacts to the BES
created by undiscovered latent failures that could cause an incorrect operation of the
RAS. Extending to longer intervals increases the reliability risk to the BES posed by an
undiscovered latent failure that could cause an incorrect operation or failure of the RAS.
The RAS‐entity is in the best position to determine the testing procedure and schedule
due to its overall knowledge of the RAS design, installation, and functionality. Functional
testing may be accomplished with end‐to‐end testing or a segmented approach. For
segmented testing, each segment of a RAS must be tested. Overlapping segments can be
tested individually negating the need for complex maintenance schedules and outages.
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PRC‐012‐2 – Remedial Action Schemes
The maximum allowable interval between functional tests is six full calendar years for RAS
that are not designated as limited impact RAS and twelve full calendar years for RAS that
are designated as limited impact RAS. The interval between tests begins on the date of
the most recent successful test for each individual segment or end‐to‐end test. A
successful test of one segment only resets the test interval clock for that segment. A
correct operation of a RAS qualifies as a functional test for those RAS segments which
operate (documentation for compliance with Requirement R5 Part 5.1). If an event causes
a partial operation of a RAS, the segments without an operation will require a separate
functional test within the maximum interval with the starting date determined by the
previous successful test of the segments that did not operate.
R8.
Each RAS‐entity shall participate in performing a functional test of each of its RAS to
verify the overall RAS performance and the proper operation of non‐Protection
System components: [Violation Risk Factor: High] [Time Horizon: Long‐term Planning]
At least once every six full calendar years for all RAS not designated as limited
impact, or
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis for a correct RAS segment or an end‐to‐end
operation (Measure M5 documentation), or dated documentation demonstrating that
a functional test of each RAS segment or an end‐to‐end test was performed in
accordance with Requirement R8.
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PRC‐012‐2 – Remedial Action Schemes
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high‐level information on existing RAS that could potentially impact the
operational and/or planning activities of that entity. Attachment 3 lists the minimum
information required for the RAS database, which includes a summary of the RAS
initiating conditions, corrective actions, and System issues being mitigated. This
information allows an entity to evaluate the reliability need for requesting more detailed
information from the RAS‐entities identified in the database contact information. The RC
is the appropriate entity to maintain the database because the RC receives the required
database information when a new or modified RAS is submitted for review. The twelve
full calendar month time frame is aligned with industry practice and allows sufficient time
for the RC to collect the appropriate information from RAS‐entities and update the RAS
database.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS‐entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1, R3, R5, R6, R7, and R8, and Measures M1, M3, M5, M6, M7,
and M8 since the last audit, unless directed by its Compliance Enforcement
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PRC‐012‐2 – Remedial Action Schemes
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M2 and M9 since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS‐entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non‐compliant, it shall
keep information related to the non‐compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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PRC‐012‐2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS‐entity failed to
provide the information
identified in Attachment 1 to
each Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30 full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90 full
calendar days.
Draft 23 of PRC‐012‐2
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Page 15 of 55
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS‐entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
R4.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greater than 60 full calendar
months butwas late by less
than or equal to 6130 full
calendar monthsdays.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greaterwas late by more
than 6130 full calendar
monthsdays but less than or
equal to 6260 full‐ calendar
monthsdays.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greaterwas late by more
than 6260 full calendar
monthsdays but less than or
equal to 6390 full calendar
monthsdays.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but in
greaterwas late by more
than 6390 full calendar
monthsdays.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate two or more of
the Parts 4.1.1 through
4.1.45.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
Draft 23 of PRC‐012‐2
November 2015February 2016
Page 16 of 55
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
to evaluate one of the Parts
4.1.1 through 4.1.45.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
R5.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by less than or
equal to 10 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 30 full
calendar days.
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to address two or
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
Draft 23 of PRC‐012‐2
November 2015February 2016
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PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
failed to address one of the
Parts 5.1.1 through 5.1.4.
more of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
(Part 5.2) to one or more of
the reviewing Reliability
Coordinator(s).
OR
The RAS‐entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10 full calendar days.
Draft 23 of PRC‐012‐2
November 2015February 2016
Page 18 of 55
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30 full
calendar days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
OR
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The RAS‐entity developed a
Corrective Action Plan but
failed to submit it to one or
more of its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6.
OR
The RAS‐entity failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS‐entity implemented N/A
a CAP in accordance with
Requirement R7, Part 7.1,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed, or failed
to notify (Part 7.3) each of
the reviewing Reliability
Coordinator(s) of the
updated CAP or completion
of the CAP.
N/A
The RAS‐entity failed to
implement a CAP in
accordance with
Requirement R7, Part 7.1.
R8.
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
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November 2015February 2016
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The RAS‐entity performed
the functional test for a RAS
as specified in Requirement
PRC‐012‐2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
R8, but was late by less than
or equal to 30 full calendar
days.
R9.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30 full calendar days.
Draft 23 of PRC‐012‐2
November 2015February 2016
Page 20 of 55
High VSL
Severe VSL
R8, but was late by more
than 30 full calendar days
but less than or equal to 60
full calendar days.
R8, but was late by more
than 60 full calendar days
but less than or equal to 90
full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
R8, but was late by more
than 90 full calendar days.
OR
The RAS‐entity failed to
perform the functional test
for a RAS as specified in
Requirement R8.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90 full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
PRC‐012‐2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
Date
Action
Change Tracking
1
Adopted by NERC Board of Trustees
New
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Page 21 of 55
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified2 RAS that the RAS‐entity must document and provide to
the reviewing Reliability Coordinator(s) (RC). If an item on this list does not apply to a
specific RAS, a response of “Not Applicable” for that item is appropriate. When RAS are
submitted for functional modification review and approval, only the proposed modifications
to that RAS require review; however, the RAS‐entity must provide a summary of the existing
functionality. The RC may request additional information on any aspect of the RAS as well as
any reliability issue related to the RAS. Additional entities (without decision authority) may
be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐
voltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
2
f. Action(s) to be taken by the RAS.
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond error correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
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Attachments
g. Identification of limited impact3 RAS.
h. Any additional explanation relevant to high‐level understanding of the RAS.
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS‐entity proposed designation asproposal and justification for limited impact or
notdesignation, if applicable.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
8. Identification of other affected RCs.
3
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact.
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Attachments
III. Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, control actions, logic processing, control actions, and
monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in‐service or is being
maintained.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective.
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS‐entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability‐related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any aspect of the RAS as well as any reliability issue related to the RAS. If a
checklist item is not relevant to a particular RAS, it should be noted as “Not Applicable.” If
reliability considerations are identified during the review, the considerations and the proposed
resolutions should be documented with the remaining applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The designed timing of RAS operation(s) is appropriate to its BES performance
objectives.
2.3.
The RAS arming conditions, if applicable, are appropriate to its System
performance objectives.
3.4.
The RAS avoids adverse interactions with other RAS, and protection and control
systems.
4.5.
The effects of RAS incorrect operation, including inadvertent operation and
failure to operate, have been identified.
5.6.
Determination whether or not the RAS is “limited impact.5” A RAS designated as
limited impact cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations.
6.7.
Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
4
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond error correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
5
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
Draft 23 of PRC‐012‐2
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Attachments
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7.8.
The effects of future BES modifications on the design and operation of the RAS
have been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. The timing of RAS action(s) is appropriate to its BES performance objectives.
3.2.
Except for limited impact RAS as determined by the RC, a single component
failure in a RAS does not prevent the BES from meeting the same performance
requirements as those required for the events and conditions for which the RAS is
designed.
4.3.
The RAS design facilitates periodic testing and maintenance.
5.4.
The mechanism or procedure by which the RAS is armed is clearly described, and
is appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
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November 2015February 2016
Page 26 of 55
Attachments
Attachment 3
Database Information
1. RAS name.
2. Each RAS‐entity and contact information.
3. Expected or actual in‐service date; most recent RC‐approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐ or over‐voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact6 RAS.
8. Any additional explanation relevant to high‐level understanding of the RAS.
6
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
Draft 23 of PRC‐012‐2
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Supplemental Material
Technical Justifications for RequirementsJustification
Applicability
4.1.1 Reliability Coordinator
The Reliability Coordinator (RC) is the best‐suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest‐area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide‐
Area purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS‐entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best‐suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS‐entity
The RAS‐entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RAS‐
entity has sole responsibility for all the activities assigned within the standard to the RAS‐entity.
If the RAS (RAS components) have more than one owner, then each separate RAS component
owner is a RAS‐entity and is obligated to participate in various activities identified by the
Requirements.
The standard does not stipulate particular compliance methods. RAS‐entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS‐entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS‐entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Limited impact
RAS are unique and customized assemblages of protection and control equipment that vary in
complexity and impact on the reliability of the BES. These differences in RAS design, action, and
risk to the BES are identified and verified within the construct of Requirements R1‐R4 of PRC‐
012‐2.
Draft 23 of PRC‐012‐2
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Supplemental Material
The reviewing RC has the authority to designate a RAS as limited impact if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The reviewing RC is the sole arbiter for determining whether a RAS qualifies for the
limited impact designation. The limited impact designation is available to any RAS in any Region
provided the reviewing RC determines the RAS poses a low risk to BES reliability.
The limited impact designation is modeled after the Local Area Protection Scheme (LAPS)
classification in WECC (Western Electricity Coordinating Council) and the Type 3 classification in
NPCC (Northeast Power Coordinating Council). The following information describing the
aforementioned WECC and NPCC RAS is excerpted from the respective regional
documentation7.The drafting team notes that the information below represents the state of the
WECC and NPCC regional processes at the time of this standard development and is subject to
change before the effective date of PRC‐012‐2.
WECC: Local Area Protection Scheme (LAPS)
A Remedial Action Scheme (RAS) whose failure to operate would NOT result in any of the
following:
•
•
•
Violations of TPL‐001‐WECC‐RBP System Performance RBP,
Maximum load loss ≥ 300 MW,
Maximum generation loss ≥ 1000 MW.
NPCC: Type III
An SPS whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for
classification:
Significant adverse impact – With due regard for the maximum operating capability of the
affected systems, one or more of the following conditions arising from faults or disturbances,
shall be deemed as having significant adverse impact:
a. system instability;
b. unacceptable system dynamic response or equipment tripping;
c. voltage levels in violation of applicable emergency limits;
d. loadings on transmission facilities in violation of applicable emergency limits;
e. unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and
number of system elements contained will vary based on system characteristics. A local area
may be relatively large geographically with relatively few buses in a sparse system, or be
7
WECC Procedure to Submit a RAS for Assessment Information Required to Assess the Reliability of a RAS
Guideline, Revised 10/28/2013 | NPCC Regional Reliability Reference Directory # 7, Special Protection Systems,
Version 2, 3/31/2015
Draft 23 of PRC‐012‐2
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Supplemental Material
relatively small geographically with a relatively large number of buses in a densely
networked system.
Because the drafting team modeled the limited impact designation after the WECC and NPCC
classifications, each RAS implemented prior to the effective date of PRC‐012‐2 that has been
through the regional review processes of WECC or NPCC and classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3 in NPCC, is recognized as a limited impact RAS
upon the effective date of PRC‐012‐2 and is subject to all applicable requirements.
To propose an existing RAS (a RAS implemented prior to the effective date of PRC‐012‐2) be
designated as limited impact by the reviewing RC, the RAS‐entity must prepare and submit the
appropriate Attachment 1 information that includes the technical justification (evaluations)
documenting that the System can meet the performance requirements (specified in
Requirement R4, Parts 4.1.4 and 4.1.5) resulting from a single RAS component malfunction or
failure, respectively.
There is nothing that precludes a RAS‐entity from working with the reviewing RC during the
implementation period of PRC‐012‐2, in anticipation of the standard becoming enforceable.
However, even if the reviewing RC determines the RAS qualifies as limited impact, the
designation is not relevant until the standard becomes effective. Until then, the existing
regional processes remain in effect as well as the existing RAS classifications or lack thereof.
An example of a scheme that could be recognized as a limited impact RAS is a load shedding or
generation rejection scheme used to mitigate the overload of a BES transmission line. The
inadvertent operation of such a scheme would cause the loss of either a certain amount of
generation or load. The evaluation by the RAS‐entity should demonstrate that the loss of this
amount of generation or load, without the associated contingency for RAS operation actually
occurring, is acceptable and not detrimental to the reliability of BES; e.g., in terms of frequency
and voltage stability. The failure of that scheme to operate when intended could potentially
lead to the overloading of a transmission line beyond its acceptable rating. The RAS‐entity
would need to demonstrate that this overload, while in excess of the applicable Facility Rating,
is not detrimental to the BES outside the contained area (predetermined by studies) affected by
the contingency.
Another example of a limited‐impact RAS is a scheme used to protect BES equipment from
damage caused by overvoltage through generation rejection or equipment tripping.
Another example of a limited‐impact RAS is a centrally‐controlled undervoltage load shedding
scheme used to protect a contained area (predetermined by studies) of the BES against voltage
collapse.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
Draft 23 of PRC‐012‐2
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Supplemental Material
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Functional modifications consists of any of the following:
Changes to System conditions or Contingencies monitored by the RAS
Changes to the actions the RAS is designed to initiate
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original
functionality of existing components
Changes to RAS logic beyond error correcting existing errors
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in‐kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that uses similar
functions. For instance, if a RAS included a CO‐11 relay which was replaced by an IAC‐53 relay,
that would be an in‐kind replacement. If the CO‐11 relay were replaced by a microprocessor
SEL‐451 relay that used only the same functions as the original CO‐11 relay, that would also be
an in‐kind replacement; however, if the SEL‐451 relay was used to add new logic to what the
CO‐11 relay had provided, then the replacement relay would be a functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. For example, System conditions require a RAS to be armed when the
combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to Requirement
R4, or other assessment, indicates that the arming level should be reduced to 450 MW without
requiring any other RAS changes that would not be a functional modification. Similarly, if a RAS
is designed to shed load to reduce loading on a particular line below 1000 amps, then a change
in the load shedding trigger from 1000 amps to 1100 amps would not be a functional
modification.
Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs to the RAS) and the logic to recognize the specific line outages would
change, while the generation reduction (RAS output) requirement may or may not change,
depending on which line is out of service. These required RAS changes would be a functional
modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for such functional modifications
may be identified in several ways including but not limited to the Planning evaluations pursuant
to R4, incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning
assessments related to future additions or modifications of other facilities.
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Supplemental Material
To facilitate a review that promotes reliability, the RAS‐entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS‐entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS‐entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RAS‐
entity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS‐entity(ies). An independent review by a multi‐disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the
widest‐area reliability perspective of all functional entities and an awareness of reliability issues
in neighboring RC Areas. This Wide Area purview facilitates the evaluation of interactions
among separate RAS as well as interactions among the RAS and other protection and control
systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS‐entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement. It is recognized that the RC does not
possesses more information or ability than anticipated by their functional registration as
designated by NERC. The NERC Functional Model is a guideline for the development of
standards and their applicability and does not contain compliance requirements. If Reliability
Standards address functions that are not described in the model, the Reliability Standard
requirements take precedence over the Functional Model. For further reference, please see the
Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
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Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
for review. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
Requirement R3
Requirement R3 mandates that each RAS‐entity resolve all reliability issues (pertaining to its
RAS) identified during the RAS review by the reviewing Reliability Coordinators. Examples of
reliability issues include a lack of dependability, security, or coordination. RC approval of a RAS
is considered to be obtained when the reviewing RC’s feedback to each RAS‐entity indicates
that either no reliability issues were identified during the review or all identified reliability
issues were resolved to the RC’s satisfaction.
Dependability is a component of reliability that is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over‐tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability that is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re‐configuring the System. Such actions, if inadvertently taken, are undesirable
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC‐
012‐2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS‐entity or the reviewing RC(s) may
have alternative ideas or methods available to resolve the issue(s). In either case, the concern
needs to be resolved in deference to reliability, and the RC has the final decision.
A specific time period for the RAS‐entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS‐entity to effect a timely
implementation.
A specific time period for the RC to respond to the RAS‐entity following the RAS review is also
not necessary because the RC will be aware of (1) any reliability issues associated with the RAS
not being in service and (2) the RAS‐entity’s schedule to implement the RAS to address those
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reliability issues. Since the RC is the ultimate arbiter of BES operating reliability, resolving
reliability issues is a priority for the RC and serves as an incentive to expeditiously respond to
the RAS‐entity.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every
60five full calendar monthsyears. The purpose of a periodic RAS evaluation is to verify the
continued effectiveness and coordination of the RAS, as well as to verify that requirements for
BES performance following inadvertent RAS operation and single component failure continue to
be satisfied. A periodic evaluation is required because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it interacts with and impacts the
BES.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate,
cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations. Limited impact RAS are not
subject to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to the
design with minimal benefit to BES reliability.
A RAS implemented after the effective date of this standard can only be designated as limited
impact by the reviewing RC(s). A RAS implemented prior to the effective date of PRC‐012‐2 that
has been through the regional review processes of WECC or NPCC and is classified as either a
Local Area Protection Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited
impact RAS upon the effective date of PRC‐012‐2 for the purposes of this standard and is
subject to all applicable requirements.
Requirement R4 also clarifies that the RAS single component failure and inadvertent operation
tests do not apply to RAS which are determined to be limited impact. Requiring a limited impact
RAS to meet the single component failure and inadvertent operation tests would just add
complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within sixtyfive
full calendar monthsyears of the effective date of PRC‐012‐2. For new or functionally modified
RAS, the initial performance of the requirement must be completed within sixtyfive full
calendar monthsyears of the RAS approval date by the reviewing RC(s). SixtyFive full calendar
monthsyears was selected as the maximum time frame between evaluations based on the time
frames for similar requirements in Reliability Standards PRC‐006, PRC‐010, and PRC‐014. The
RAS evaluation can be performed sooner if it is determined that material changes to System
topology or System operating conditions could potentially impact the effectiveness or
coordination of the RAS. System changes also have the potential to alter the reliability impact
of limited impact RAS on the BES. Requirement 4, Part 4.1.3 explicitly requires the periodic
evaluation of limited impact RAS to verify the limited impact designation remains applicable.
The periodic RAS evaluation will typically lead to one of the following outcomes: 1) affirmation
that the existing RAS is effective; 2) identification of changes needed to the existing RAS; or, 3)
justification for RAS retirement.
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The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.45) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The PC is the functional entity best suited to perform the
analyses because they have a wide‐area planning perspective. To promote reliability, the PC is
required to provide the results of the evaluation to each RAS‐entity and reviewing RC, as well as
each impacted Planning Coordinator and Transmission Plannerimpacted Transmission Planner
and Planning Coordinator, in addition to each reviewing RC and RAS‐entity. In cases where a
RAS crosses PC boundaries, each affected PC is responsible for conducting either individual
evaluations or participating in a coordinated evaluation.
The intent of Requirement R4, Part 4.1.34 is to require that the possible inadvertent operation
of the RAS (other than limited impact RAS), caused by the malfunction of a single component of
the RAS, meet the same System performance requirements as those required for the
Contingency(ies) or System conditions for which it is designed. If the RAS is designed to meet
one of the planning events (P0‐P7) in TPL‐001‐4, the possible inadvertent operation of the RAS
must meet the same performance requirements listed in the standard for that planning event.
The requirement clarifies that the inadvertent operation to be considered is only that caused by
the malfunction of a single RAS component. This allows features to be designed into the RAS to
improve security, such that inadvertent operation due to malfunction of a single component is
prevented; otherwise, the RAS inadvertent operation must satisfy Requirement R4, Part 4.1.34.
The intent of Requirement R4, Part 4.1.34 is also to require that the possible inadvertent
operation of the RAS (other than limited impact RAS) installed for an extreme event in TPL‐001‐
4 or for some other Contingency or System conditions not defined in TPL‐001‐4 (therefore
without performance requirements), meet the minimum System performance requirements of
Category P7 in Table 1 of NERC Reliability Standard TPL‐001‐4. However, instead of referring to
the TPL standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.34.1 – 4.1.34.5) are the ones that are common to all planning events (P0‐P7) listed in
TPL‐001‐4.
With reference to Requirement 4, Part 4.1.34, note that the only differences in performance
requirements among the TPL (P0‐P7) events (not common to all of them) concern Non‐
Consequential Load Loss and interruption of Firm Transmission Service. It is not necessary for
Requirement R4, Part 4.1.34 to specify performance requirements related to these areas
because a RAS is only allowed to drop non‐consequential load or interrupt Firm Transmission
Service if that action is allowed for the Contingency for which it is designed. Therefore, the
inadvertent operation should automatically meet Non‐Consequential Load Loss or interrupting
Firm Transmission Service performance requirements for the Contingency(ies) for which it was
designed.
Part 4.1.45 requires that a single component failure in the RAS (other than limited impact RAS),
when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS is designed. This analysis is needed to
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ensure that changing System conditions do not result in the single component failure
requirement not being met.
Requirements for inadvertent RAS operation (Requirement R4, Part 4.1.34) and single
component failure (Requirement R4, Part 4.1.45) are reviewed by the reviewing RC(s) before a
new or functionally modified RAS is placed in‐service, and are typically satisfied by specific
design considerations. Although the scope of the periodic evaluation does not include a new
design review, it is possible that a design which previously satisfied requirements for
inadvertent RAS operation and single component failure may fail to satisfy these requirements
at a later time, and must be evaluated with respect to the current System. For example, if the
actions of a particular RAS include tripping load, load growth could occur over time that impacts
the amount of load to be tripped. These changes could result in tripping too much load upon
inadvertent operation and result in violations of Facility Ratings. Alternatively, the RAS might be
designed to trip more load than necessary (i.e., “over trip”) in order to satisfy single component
failure requirements. System changes could result in too little load being tripped and
unacceptable BES performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC‐004‐4 regarding
the investigation of a Protection System Misoperation; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
the RAS‐entity(s) is required to provide the results of RAS operational performance analyses to
its reviewing RC(s).) if the analyses revealed a deficiency.
The RAS‐entity(ies) may need to collaborate with its associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS‐entity for a RAS, the RAS‐entities would collaborate on theto conduct and
submit a single, coordinated operational performance analysis.
Requirement R6
RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may be identified
in the periodic RAS evaluation conducted by the PC in Requirement R4, in the operational
analysis conducted by the RAS‐entity in Requirement R5, or in the functional test performed by
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the RAS‐entity(ies) in Requirement R8. To mitigate potential reliability risks, Requirement R6
mandates that each RAS‐entity participate in developing a CAP that establishes the mitigation
actions and timetable necessary to address the deficiency.
The RAS‐entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS‐entity(ies) may request assistance with development of the
CAP from other parties such as its Transmission Planner or Planning Coordinator; however, the
RAS‐entity has the responsibility for compliance with this requirement.
A CAP may require functional changes be made to a RAS. In this case, Attachment 1 information
must be submitted to the reviewing RC(s), an RC review must be performed to obtain RC
approval before the RAS‐entity can place RAS modifications in‐service, per Requirements R1,
R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering or consulting work. A timeframe of six full calendar months is allotted to allow
enough time for RAS‐entity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. Ideally, when there is more than one RAS‐
entity for a RAS, the RAS‐entities would collaborate to develop and submit a single, coordinated
CAP. A RAS deficiency may require the RC or Transmission Operator to impose operating
restrictions so the System can operate in a reliable way until the RAS deficiency is resolved. The
possibility of such operating restrictions will incent the RAS‐entity to resolve the issue as quickly
as possible.
The following are example situations of when a CAP is required:
A determination after a RAS operation/non‐operation investigation that the RAS did not
meet performance expectations or did not operate as designed.
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
Equipment failures.
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
Requirement R7 mandates that each RAS‐entity implement its CAP developed in Requirement
R6 which mitigates the deficiencies identified in Requirements R4, R5, or R8. By definition, a
CAP is: “A list of actions and an associated timetable for implementation to remedy a specific
problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. If the CAP is changed, the RAS‐entity must notify the reviewing Reliability
Coordinator(s). The RAS‐entity must also notify the Reliability Coordinator(s) when the CAP has
been completed.
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The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS‐entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non‐Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in‐service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC‐005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed with minimum impact to the
BES and should align with expected results. The RAS‐entity is in the best position to determine
the testing procedure and schedule due to their overall knowledge of the RAS design,
installation, and functionality. Periodic testing provides the RAS‐entity assurance that latent
failures may be identified and also promotes identification of changes in the System that may
have introduced latent failures.
The six and twelve full calendar year functional testing intervals are greater than the annual or
bi‐annual periodic testing performed in some NERC Regions. However, these intervals are a
balance between the resources required to perform the testing and the potential reliability
impacts to the BES created by undiscovered latent failures that could cause an incorrect
operation of the RAS. Longer test intervals for limited impact RAS are acceptable because
incorrect operations or failures to operate present a low reliability risk to the Bulk Power
System.
Functional testing is not synonymous with end‐to‐end testing. End‐to‐end testing is an
acceptable method but may not be feasible for many RAS. When end‐to‐end testing is not
possible, a RAS‐entity may use a segmented functional testing approach. The segments can be
tested individually negating the need for complex maintenance schedules. In addition, actual
RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does not
operate in its entirety during a System event or System conditions do not allow an end‐to‐end
scheme test, then the segmented approach should be used to fulfill this Requirement.
Functional testing includes the testing of all RAS inputs used for detection, arming, operating,
and data collection. Functional testing also includes, by default operates the processing logic
and infrastructure of a RAS, but focuses on the RAS inputs as well as the action initiationactions
initiated by RAS outputs to address the System condition(s) for which the RAS is designed. All
segments and components of a RAS must be tested or have proven operations within the
applicable maximum test interval to demonstrate compliance with the Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
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devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC‐005, Table 1‐1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up‐to the protective
relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3‐8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well‐defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component‐level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of Contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real‐time) to
the Transmission Operator via PRC‐001, Requirement R6, then to the RC via TOP‐001‐3,
Requirement R8. See Phase 2 of Project 2007‐06 for the mapping document from PRC‐001 to
other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end‐to‐end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS‐entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
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maximum test interval that started on the date of the previous successful test of those (non‐
operating) segments in order to be compliant with Requirement R8.
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Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available to entities with a potential reliability need.. Attachment 3
contains the minimum information that is required to be included about each RAS listed in the
database. Additional information can be requested by the RC.
The database enables the RC to provide other entities high‐level information on existing RAS
that could potentially impact the operational and/or planning activities of that entity. The
information provided is sufficient for an entity with a reliability need to evaluate whether the
RAS can impact its System. For example, a RAS performing generation rejection to mitigate an
overload on a transmission line may cause a power flow change within an adjacent entity area.
This entity should be able to evaluate the risk that a RAS poses to its System from the high‐level
information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS‐entity from the RC.
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Process Flow Diagram
The diagram below depicts the process flow of the PRC‐012‐2 requirements.
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS‐entity(ies) to provide a detailed list of information
describing the RAS to the reviewing RC. If there are multiple RAS‐entities for a single RAS,
information will be needed from all RAS‐entities. Ideally, in such cases, a single RAS‐entity will
take the lead to compile all the data identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide‐ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified8 RAS that the RAS‐entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS‐entity
provides a summary of the existing RAS functionality.
I.
General
1. Information such as maps, one‐line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single‐line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre‐ and post‐modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC‐012‐2, Requirements R5 and R7]
8
Functionally Modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond error correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
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Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name.
b. Each RAS‐entity and contact information.
c. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date;
most recent 60five full calendar monthyear (Requirement R4) evaluation date; and,
date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under‐/over‐voltage,
slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (initiating conditions).
f. Corrective action taken by the RAS.
g. Identification of limited impact9 RAS.
h. Any additional explanation relevant to high level understanding of the RAS.
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical System
Contingencies or other operating conditions when RAS action is intended to occur.
If no arming conditions are required, this should also be stated.
9
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. See Attachment 2 for a description of the limited impact determination by the Reliability
Coordinator. A RAS implemented prior to the effective date of this standard that has been through the regional
review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited
impact.
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c. Event‐based RAS are triggered by specific Contingencies that initiate mitigating
action. Condition‐based RAS may also be initiated by specific Contingencies, but
specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and whenthe date those technical studies
were performed. [Reference NEC Reliability Standard PRC‐014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS‐related operations.
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC‐014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. RAS‐entity proposed designation as “proposal and justification for limited impact” or not
designation, if applicable.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard PRC‐012‐2 that has been
through the regional review process and designated asprocesses of WECC or NPCC and
is classified as either a Local Area Protection Scheme (LAPS) in WECC or a Type 3 in
NPCC, Type 2 in ERCOT, or LAPS in WECC will be is recognized as a limited impact RAS
upon the effective date of PRC‐012‐2 for the purposes of Requirement 4, Parts 4.1.3 and
4.1.4this standard and is subject to all applicable requirements.
6. Documentation showing that describing the System performance resulting from the
possible inadvertent operation of the RAS resulting from , except for limited impact RAS,
caused by any single RAS component malfunction satisfies. Single component
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Supplemental Material
malfunctions in a RAS not determined to be limited impact must satisfy all of the
following:
[Reference NERC Reliability Standard PRC‐012, R1.4]
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC‐012, R1.5 and PRC‐014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or re‐
configuring the System. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available fault duty,
which can affect distance relay overcurrent (“fault detector”) supervision and ground
overcurrent protection coordination.
8. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be
designed to be secure. Several types of devices have been commonly used as disturbance,
condition, or status detectors:
Line open status (event detectors),
Protective relay inputs and outputs (event and parameter detectors),
Transducer and IED (analog) inputs (parameter and response detectors),
Rate of change (parameter and response detectors).
DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by
Draft 23 of PRC‐012‐2
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Supplemental Material
PRC‐005. However, redundant RAS systems, when used, should be supplied from
separately protected (fused or breakered) circuits.
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Supplemental Material
Communications: Telecommunications Channels and Transfer Trip Equipment
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non‐deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel
or equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS‐entity, or
perhaps leased from another entity familiar with the necessary reliability requirements.
All channel equipment should be monitored and alarmed to the dispatch center so that
timely diagnostic and repair action shall take place upon failure. Publicly switched
telephone networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel
working on the channel can readily identify the proper circuit. Channels between entities
should be identified with a common name at all terminals.
Transfer Trip
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions
may be required at different arming levels or for different Contingencies. Scheme logic
may be achievable by something as simple as wiring a few auxiliary relay contacts or by
much more complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units
(RTUs), and logic processors. Single‐function relays have been used historically to
implement RAS, but this approach is now less common except for very simple new RAS or
minor additions to existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS
actions at the sites where action is required.
Monitoring by SCADA/EMS should include at least
Whether the scheme is in‐service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in‐service or out of service.
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Supplemental Material
For RAS that are armed automatically, these two states are independent because
a RAS that has been placed in‐service may be armed or unarmed based on
whether the automatic arming criteria have been met.
The current operational state of the scheme (available or not).
In cases where the RAS requires single component failure performance; e.g.,
redundancy, the minimal status indications should be provided separately for each
system.
The minimum status is generally sufficient for operational purposes; however,
where possible it is often useful to provide additional information regarding
partial failures or the status of critical components to allow the RAS‐entity to
more efficiently troubleshoot a reported failure. Whether this capability exists
will depend in part on the design and vintage of equipment used in the RAS.
While all schemes should provide the minimum level of monitoring, new
schemes should be designed with the objective of providing monitoring at least
similar to what is provided for microprocessor‐based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC‐012, R1.2 and PRC‐013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line‐charging current;
c. Breaker trip coil current monitoring—typically used when high‐speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of the
aforementioned, out of step, etc. are dependent on specific scheme requirements,
but some forms may substitute for or enhance other monitoring described in items
‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in‐service or is being
maintained.
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Supplemental Material
In this context, a multifunction device (e.g., microprocessor‐based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor‐based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi‐function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL‐001‐4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective. [Reference NERC Reliability Standard PRC‐012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement. Acceptable methods to achieve this objective
include, but are not limited to the following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
Protective or auxiliary relays used by the RAS.
ii.
Communications systems necessary for correct operation of the RAS.
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Supplemental Material
iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation due to that single component failure will still result in
satisfactory System performance, as long as tripping the total armed amount of load
or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re‐dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS‐entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies and technical justifications, if applicable, upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Supplemental Material
Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent‐wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability‐related considerations relevant to various aspects of RAS design and
implementation.
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
The name used to identify the RAS.
2. Each RAS‐entity and contact information.
A reliable phone number or email address should be included to contact each RAS‐entity
if more information is needed.
3. Expected or actual in‐service date; most recent (Requirement R3) RC‐approval date; most
recent 60five full calendar monthyear (Requirement R4) evaluation date; and, date of
retirement, if applicable.
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under‐/over‐voltage, slow voltage
recovery).
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the Contingencies or System conditions for which the RAS was designed
(initiating conditions).
A high level summary of the conditions/Contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
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Supplemental Material
7. Identification of limited impact10 RAS.
Specify whether or not the RAS is designated as limited impact.
8. Any additional explanation relevant to high‐level understanding of the RAS.
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
10
A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute
to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations. A RAS implemented prior to the effective date of this standard that has been through the
regional review process and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as
limited impact.
Draft 23 of PRC‐012‐2
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Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
PRC‐012‐2 – Remedial Action Schemes
Requested Retirements
PRC‐012‐1 – Remedial Action Scheme Review Procedure
PRC‐013‐1 – Remedial Action Scheme Database
PRC‐014‐1 – Remedial Action Scheme Assessment
PRC‐015‐1 – Remedial Action Scheme Data and Documentation
PRC‐016‐1 – Remedial Action Scheme Misoperations
Applicable Entities
Reliability Coordinator
Planning Coordinator
RAS‐entity – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or
part of a RAS
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for Remedial
Action Scheme (“RAS”) and associated revisions to related Reliability Standards to consolidate that term
with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not
enforceable, NERC revised these standards to account for the RAS definition revision and changed
relevant version numbers to reflect the change. Because of this change, NERC requested retirement of
PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0, and provided, for informational purposes only, updated
Reliability Standards PRC‐012‐1, PRC‐013‐1, and PRC‐014‐1. In the same Petition, NERC requested
retirement of PRC‐015‐0 and PRC‐016‐0.1 and approval of Reliability Standards PRC‐015‐1 and PRC‐016‐
1, again implementing changes stemming from the revised definition of RAS.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the
Commission issued a Final Order approving the RAS definition and associated standards.
General Considerations
Reliability Standard PRC‐012‐2 was developed to consolidate previously unapproved standards which
were designated by the Commission as “fill‐in‐the‐blank” standards and to revise other RAS‐related
standards. Reliability Standard PRC‐012‐2 also provides clear and unambiguous responsibilities to the
specific users, owners, and operators of the Bulk‐Power System. Reliability Standard PRC‐012‐2
establishes a new working framework between RAS‐entities, PCs, and RCs, and this new framework will
involve considerable start‐up effort. As such, implementation of Reliability Standard PRC‐012‐2 will occur
over a thirty six (36) month period after approval of the standard by applicable governmental authorities.
Limited Impact RAS
A RAS implemented prior to the effective date of PRC‐012‐2 that has been through the regional review
processes of WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC or
a Type 3 in NPCC is recognized as a limited impact RAS upon the effective date of PRC‐012‐2 and is subject
to all applicable requirements.
Effective Date
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐012‐2
shall become effective on the first day of the first calendar quarter that is thirty six (36) months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Provisions concerning the initial performance of
obligations under Requirements R4, R8, and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is thirty six (36) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Provisions concerning the initial performance of obligations under Requirements R4, R8, and R9 are
outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within five
(5) full calendar years after the effective date of PRC‐012‐2, as described above.
For new or functionally modified RAS, the initial performance of Requirement R4 must be completed
within five (5) full calendar years after the date that the RAS is approved by the reviewing RC(s) under
Requirement R3.
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years after the effective date for PRC‐012‐2,
as described above.
For each RAS designated as limited impact, initial performance of obligations under Requirement R8 must
be completed at least once within twelve (12) full calendar years after the effective date for PRC‐012‐2,
as described above.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
February 2016
Page 2 of 3
Requirement R9
For each Reliability Coordinator that does not have a RAS database, the initial obligation under
Requirement R9 is to establish a database by the effective date of PRC‐012‐2.
Each Reliability Coordinator will perform the obligation of Requirement R9 within twelve full calendar
months after the effective date of PRC‐012‐2, as described above.
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the effective date of PRC‐
012‐2 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
February 2016
Page 3 of 3
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
PRC‐012‐2 – Remedial Action Schemes
Requested Retirements
PRC‐012‐1 – Remedial Action Scheme Review Procedure
PRC‐013‐1 – Remedial Action Scheme Database
PRC‐014‐1 – Remedial Action Scheme Assessment
PRC‐015‐1 – Remedial Action Scheme Data and Documentation
PRC‐016‐1 – Remedial Action Scheme Misoperations
Applicable Entities
Reliability Coordinator
Planning Coordinator
RAS‐entity – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or
part of a RAS
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for Remedial
Action Scheme (“RAS”) and associated revisions to related Reliability Standards to consolidate that term
with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not
enforceable, NERC revised these standards to account for the RAS definition revision and changed
relevant version numbers to reflect the change. Because of this change, NERC requested retirement of
PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0, and provided, for informational purposes only, updated
Reliability Standards PRC‐012‐1, PRC‐013‐1, and PRC‐014‐1. In the same Petition, NERC requested
retirement of PRC‐015‐0 and PRC‐016‐0.1 and approval of Reliability Standards PRC‐015‐1 and PRC‐016‐
1, again implementing changes stemming from the revised definition of RAS.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the
Commission issued a Final Order approving the RAS definition and associated standards.
General Considerations
Reliability Standard PRC‐012‐2 was developed to consolidate previously unapproved standards which
were designated by the Commission as “fill‐in‐the‐blank” standards and to revise other RAS‐related
standards. Reliability Standard PRC‐012‐2 also provides clear and unambiguous responsibilities to the
specific users, owners, and operators of the Bulk‐Power System. Reliability Standard PRC‐012‐2
establishes a new working framework between RAS‐entities, PCs, and RCs, and this new framework will
involve considerable start‐up effort. As such, implementation of Reliability Standard PRC‐012‐2 will occur
over a thirty six (36) month period after approval of the standard by applicable governmental authorities.
Limited Impact RAS
A RAS implemented prior to the effective date of PRC‐012‐2 that has been through the regional review
processes of WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC or
a Type 3 in NPCC is recognized as a limited impact RAS upon the effective date of PRC‐012‐2 and is subject
to all applicable requirements.
Effective Date
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐012‐2
shall become effective on the first day of the first calendar quarter that is thirty six (36) months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Provisions concerning the initial performance of
obligations under Requirements R4, R8, and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is thirty six (36) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Provisions concerning the initial performance of obligations under Requirements R4, R8, and R9 are
outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within sixty
(60five (5) full calendar months ofyears after the effective date of PRC‐012‐2, as described above.
For new or functionally modified RAS, the initial performance of Requirement R4 must be completed
within sixty (60five (5) full calendar months ofyears after the date that the RAS is approved by the
reviewing RC(s) under Requirement R3.
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years ofafter the effective date for PRC‐012‐
2, as described above.
For each RAS designated as limited impact, initial performance of obligations under Requirement R8 must
be completed at least once within twelve (12) full calendar years ofafter the effective date for PRC‐012‐
2, as described above.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
November 2015 February 2016
Page 2 of 4
Requirement R9
For each Reliability Coordinator that does not have a RAS database upon the effective date of PRC‐012‐2,
as described above, the initial obligation under Requirement R9 is to establish a database by the effective
date of PRC‐012‐2.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
November 2015 February 2016
Page 3 of 4
Each Reliability Coordinator will perform the obligation of Requirement R9 within twelve full calendar
months after the effective date of PRC‐012‐2, as described above.
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the effective date of PRC‐
012‐2 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC‐012‐2
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
November 2015 February 2016
Page 4 of 4
Unofficial Comment Form
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
DO NOT use this form for submitting comments. Use the electronic form to submit comments on PRC012-2 – Remedial Action Schemes. The electronic comment form must be submitted by 8 p.m. Eastern,
Friday, March 18, 2016.
Documents and information about this project are available on the project page. If you have questions,
contact Standards Developer, Al McMeekin (via email), or at (404) 446-9675.
Background Information
This project is addressing all aspects of Remedial Action Schemes (RAS) contained in the RAS-related
Reliability Standards: PRC-012-1, PRC-013-1, PRC-014-1, PRC-015-1, and PRC-016-1. The maintenance of
the Protection System components associated with RAS (PRC-017-1 Remedial Action Scheme
Maintenance and Testing) are already addressed in PRC-005. PRC-012-2 addresses the testing of the nonProtection System components associated with RAS and the overall performance of the RAS.
In FERC Order No. 693 (dated March 16, 2007), the Commission identified PRC-012-0, PRC-013-0, and
PRC-014-0 as “fill-in-the-blank” standards and did not approve or remand them. These standards are
applicable to the Regional Reliability Organizations (RROs), assigning the RROs the responsibility to
establish regional procedures and databases, and to assess and document the operation, coordination,
and compliance of RAS. The deference to regional practices precludes the consistent application of RASrelated Reliability Standard requirements.
The proposed draft of PRC-012-2 corrects the applicability of the fill-in-the-blank standards by assigning
the requirement responsibilities to the specific users, owners, and operators of the Bulk-Power System;
and incorporates the reliability objectives of all the RAS-related standards.
45-day Formal Comment Period
The drafting team appreciates the feedback stakeholders provided on the previous posting. The drafting
team considered all of the comments and revised the standard and its implementation plan, making
clarifying changes to both documents. Responses to the most prevalent comments received and a
summary of the changes to the documents are located in the Consideration of Comments document
posted on the project page. Responses to individual comments are not required for a failed additional
ballot in accordance with sections 4.12 and 4.13 of the Standards Process Manual. The drafting team will
respond to all individual comments received in the last additional ballot; i.e., the passing ballot prior to
conducting the Final Ballot. If you have a specific comment that you would like to discuss, please contact
the Standards Developer, Al McMeekin at 404-446-9675 or via email Al McMeekin. Please provide your
comment, your contact information, and a convenient date and time for a discussion.
The drafting team is soliciting comments and feedback on the revised standard and its implementation
plan.
Questions
1. PRC-012-2: Requirements R4 and R6, Attachments 1 and 2, and the Supplemental Material section of
the standard were modified for clarity and completeness. Do you agree with the proposed changes? If
no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
2. Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to provide
for the initial consideration of limited impact RAS, and to clarify that the initial obligation under
Requirement R9 for a Reliability Coordinator that does not have a RAS database is to establish a RAS
database by the effective date of PRC-012-2. Do you agree with the revised Implementation Plan? If
no, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
Unofficial Comment Form | PRC-012-2 Draft 3
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS) | February 2015
2
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
R1.1. Description of the process for submitting a
proposed RAS for Regional Reliability
Organization review.
R1.2. Requirements to provide data that describes
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
shall be designed so that a single RAS
component failure, when the RAS was
intended to operate, does not prevent the
interconnected transmission system from
meeting the performance requirements
defined in Reliability Standards TPL-001-0,
TPL-002-0, and TPL-003-0.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC-012-1 R.1.1:
Covered by Requirements R1,
R2 and R3
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC-012-1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC-012-1 R.1.3:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.5
PRC-012-1 R.1.4:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2, and
Requirement R4, Part 4.1.4
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was
designed, and not exceed TPL-003-0.
PRC-012-1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
R1.5. Requirements to demonstrate the proposed
RAS will coordinate with other protection
and control systems and applicable Regional
Reliability Organization Emergency
procedures.
PRC-012-1 R.1.6:
Covered by Requirement R5
Existing Requirement in Reliability Standard
R1.6. Regional Reliability Organization definition
of misoperation.
R1.7. Requirements for analysis and
documentation of corrective action plans for
all RAS misoperations.
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
PRC-012-1 R.1.7:
Covered by Requirements R5
and R6
PRC-012-1 R.1.8:
PRC-012-2 NERC Standards
Development Process
PRC-012-1 R.1.9:
Covered by Requirement R8
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS-entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
4
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
performance and the proper operation of non-Protection
System components:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
•
At least once every six full calendar years for all
RAS not designated as limited impact, or
•
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-013-1 R1:
Covered by Requirement R9
PRC-013-1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-014-1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
PRC-014-1 R2:
Covered by Requirement R4
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
R3.1. Identification of group conducting the assessment
and the date the assessment was performed.
R3.2. Study years, system conditions, and contingencies
analyzed in the technical studies on which the
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
PRC-014-1 R3:
Covered by Requirement R4
PRC-014-1 R3.1 - R3.4:
Covered by Requirement R4
PRC-014-1 R3.5:
Covered by Requirement R6
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non-compliant
RAS.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
11
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall maintain
a list of and provide data for existing and proposed
RAS as specified in Reliability Standard PRC-013-1
R1.
PRC-015-1 R1:
Covered by Requirement R1,
Attachment 1
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC-012-1_R1 prior to being placed in
service.
PRC-015-1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
Retired P81
N/A
13
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC-012-1_R1.
Translation to New
Standard or Other Action
PRC-016-1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
PRC-016-1 R2:
Covered by Requirements R6
and R7
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
PRC-016-1 R3:
Covered by Requirements R5,
R6, and R7, Attachment 1
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
17
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
Mapping Document | February 2016
Project 2010-05.3 Phase 2 of Protection Systems (RAS)
18
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
Translation to New
Standard or Other Action
PRC‐012‐1 R.1.1:
Covered by Requirements R1,
R2 and R3
PRC‐012‐1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC‐012‐1 R.1.3:
R1.1. Description of the process for submitting a
Covered by Requirement R1,
proposed RAS for Regional Reliability
Attachments 1, Requirement
Organization review.
R2, Attachment 2 and
R1.2. Requirements to provide data that describes Requirement R4, Part 4.1.45
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
PRC‐012‐1 R.1.4:
shall be designed so that a single RAS
Covered by Requirement R1,
component failure, when the RAS was
Attachments 1, Requirement
intended to operate, does not prevent the
R2, Attachment 2, and
interconnected transmission system from
Requirement R4, Part 4.1.34
meeting the performance requirements
defined in Reliability Standards TPL‐001‐0,
TPL‐002‐0, and TPL‐003‐0.
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. Prior to placing a new or functionally modified RAS in‐
service or retiring an existing RAS, each RAS‐entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS‐entity.
R3. Prior to placing a new or functionally modified RAS in‐
service or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Planning Coordinator, at least once every 60five
full calendar monthsyears, shall:
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL‐
001‐0, TPL‐002‐0, and TPL‐003‐0) as that
required of the contingency for which it was
designed, and not exceed TPL‐003‐0.
PRC‐012‐1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.2
R1.5. Requirements to demonstrate the proposed PRC‐012‐1 R.1.6:
Covered by Requirement R5
RAS will coordinate with other protection
and control systems and applicable Regional
PRC‐012‐1 R.1.7:
Reliability Organization Emergency
Covered by Requirements R4
procedures.
R5 and R6
R1.6. Regional Reliability Organization definition
of misoperation.
PRC‐012‐1 R.1.8:
PRC‐012‐2 NERC Standards
R1.7. Requirements for analysis and
documentation of corrective action plans for Development Process
all RAS misoperations.
PRC‐012‐1 R.1.9:
R1.8. Identification of the Regional Reliability
Covered by Requirement R8
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
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New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.34.1 The BES shall remain stable.
4.1.34.2 Cascading shall not occur.
4.1.34.3 Applicable Facility Ratings shall not be
exceeded.
4.1.34.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.34.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.45 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS‐entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS‐entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
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Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
• Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS‐entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
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Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
performance and the proper operation of non‐Protection
System components:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
At least once every six full calendar years for all
RAS not designated as limited impact, or
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
Translation to New
Standard or Other Action
PRC‐013‐1 R1:
Covered by Requirement R9
PRC‐013‐1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
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New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to Retired P81
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
Translation to New
Standard or Other Action
PRC‐014‐1 R1:
Covered by Requirement R4
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New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Planning Coordinator, at least once every 60five
full calendar monthsyears, shall:
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
for compliance with NERC Reliability Standards and
Regional criteria.
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.34.1 The BES shall remain stable.
4.1.34.2 Cascading shall not occur.
4.1.34.3 Applicable Facility Ratings shall not be
exceeded.
4.1.34.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
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Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.34.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.45 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS‐entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
PRC‐014‐1 R2:
Covered by Requirement R4
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R4. Each Planning Coordinator, at least once every 60five
full calendar monthsyears, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.34.1 The BES shall remain stable.
4.1.34.2 Cascading shall not occur.
4.1.34.3 Applicable Facility Ratings shall not be
exceeded.
4.1.34.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
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Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.34.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.45 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS‐entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
PRC‐014‐1 R3:
Covered by Requirement R4
PRC‐014‐1 R3.1 ‐ R3.4:
R3.1. Identification of group conducting the assessment
Covered by Requirement R4
and the date the assessment was performed.
R3.2. Study years, system conditions, and contingencies
PRC‐014‐1 R3.5:
analyzed in the technical studies on which the
Covered by Requirement R6
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R4. Each Planning Coordinator, at least once every 60five
full calendar monthsyears, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non‐compliant
RAS.
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.34.1 The BES shall remain stable.
4.1.34.2 Cascading shall not occur.
4.1.34.3 Applicable Facility Ratings shall not be
exceeded.
4.1.34.4 BES voltages shall be within post‐
Contingency voltage limits and post‐
Contingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.34.5 Transient voltage responses shall be
within acceptable limits as established by the
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Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.45 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL‐001‐4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS‐entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
• Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
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Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
PRC‐015‐1 R1:
Distribution Provider that owns a RAS shall maintain Covered by Requirement R1,
a list of and provide data for existing and proposed Attachment 1
RAS as specified in Reliability Standard PRC‐013‐1
R1.
R1. Prior to placing a new or functionally modified RAS in‐
service or retiring an existing RAS, each RAS‐entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC‐012‐1_R1 prior to being placed in
service.
R1. Prior to placing a new or functionally modified RAS in‐
service or retiring an existing RAS, each RAS‐entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC‐015‐1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS‐entity.
R3. Prior to placing a new or functionally modified RAS in‐
service or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
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Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
R3. The Transmission Owner, Generator Owner, and
Retired P81
Distribution Provider that owns a RAS shall provide
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
N/A
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Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC‐012‐1_R1.
Translation to New
Standard or Other Action
PRC‐016‐1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS‐entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
PRC‐016‐1 R2:
Covered by Requirements R6
and R7
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R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
• Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS‐entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
PRC‐016‐1 R3:
Distribution Provider that owns a RAS shall provide Covered by Requirements R5,
documentation of the misoperation analyses and
R6, and R7, Attachment 1
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
R5. Each RAS‐entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
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Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS‐entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
• Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
• Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
• Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS‐entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
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Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
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Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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2
Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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3
NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – 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.
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to provide
the information identified in
Attachment 1 to each Reliability
Coordinator prior to placing a
new or functionally modified
RAS in‐service or retiring an
existing RAS in accordance with
Requirement R1.
6
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30 full calendar days
but less than or equal to 60 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60 full calendar days
but less than or equal to 90 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90 full calendar days.
OR
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
10
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
N/A
14
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirement R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 90 full
calendar days.
OR
OR
The Planning Coordinator
The Planning Coordinator
performed the evaluation in
performed the evaluation in
accordance with Requirement
accordance with Requirement
R4, but failed to evaluate two or
R4, but failed to evaluate one of more of the Parts 4.1.1 through
the Parts 4.1.1 through 4.1.5.
4.1.5.
OR
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
receiving entities listed in Part
4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
less than or equal to 10 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 10 full calendar days
but less than or equal to 20 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 20 full calendar days
but less than or equal to 30 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 30 full calendar days.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1.1 through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
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VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10 full calendar days.
Moderate
High
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10 full calendar days but less
than or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20 full calendar days but less
than or equal to 30 full calendar
days.
Severe
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30 full calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐entity failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐entity implemented a
N/A
CAP in accordance with
Requirement R7, Part 7.1, but
failed to update the CAP (Part
7.2) if actions or timetables
changed, or failed to notify (Part
7.3) each of the reviewing
Reliability Coordinator(s) of the
updated CAP or completion of
the CAP.
ifications for PRC‐012‐2, Requirement R7
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High
N/A
Severe
The RAS‐entity failed to
implement a CAP in accordance
with Requirement R7, Part 7.1.
30
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 90 full
calendar days.
OR
The RAS‐entity failed to perform
the functional test for a RAS as
specified in Requirement R8.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30 full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30 full calendar days but less
than or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60 full calendar days but less
than or equal to 90 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than 90
full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
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FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – 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.
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
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VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to provide
the information identified in
Attachment 1 to each Reliability
Coordinator prior to placing a
new or functionally modified
RAS in‐service or retiring an
existing RAS in accordance with
Requirement R1.
6
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30 full calendar days
but less than or equal to 60 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60 full calendar days
but less than or equal to 90 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90 full calendar days.
OR
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
10
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
N/A
14
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirement R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
The Planning Coordinator
performed the evaluation as
specified in accordance with
Requirement R4, in greater than
60 full calendar months but was
late by less than or equal to
6130 full calendar monthsdays.
The Planning Coordinator
performed the evaluation as
specified in accordance with
Requirement R4, in greaterbut
was late by more than 6130 full
calendar monthsdays but less
than or equal to 6260 full‐
calendar monthsdays.
The Planning Coordinator
performed the evaluation as
specified in accordance with
Requirement R4, in greaterbut
was late by more than 6260 full
calendar monthsdays but less
than or equal to 6390 full
calendar months. days.
Severe
The Planning Coordinator
performed the evaluation as
specified in accordance with
Requirement R4, but in
greaterwas late by more than
6390 full calendar monthsdays.
OR
The Planning Coordinator
performed the evaluation in
The Planning Coordinator
accordance with Requirement
performed the evaluation in
R4, but failed to evaluate two or
accordance with Requirement
more of the Parts 4.1.1 through
R4, but failed to evaluate one of 4.1.45.
the Parts 4.1.1 through 4.1.45.
OR
OR
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
results to one or more of the
receiving entities listed in Part
4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
less than or equal to 10 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 10 full calendar days
but less than or equal to 20 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 20 full calendar days
but less than or equal to 30 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 30 full calendar days.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1.1 through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
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VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10 full calendar days.
Moderate
High
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10 full calendar days but less
than or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20 full calendar days but less
than or equal to 30 full calendar
days.
Severe
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30 full calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐entity failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐entity implemented a
N/A
CAP in accordance with
Requirement R7, Part 7.1, but
failed to update the CAP (Part
7.2) if actions or timetables
changed, or failed to notify (Part
7.3) each of the reviewing
Reliability Coordinator(s) of the
updated CAP or completion of
the CAP.
ifications for PRC‐012‐2, Requirement R7
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High
N/A
Severe
The RAS‐entity failed to
implement a CAP in accordance
with Requirement R7, Part 7.1.
30
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 90 full
calendar days.
OR
The RAS‐entity failed to perform
the functional test for a RAS as
specified in Requirement R8.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30 full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30 full calendar days but less
than or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60 full calendar days but less
than or equal to 90 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than 90
full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
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FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
February 2016
Table of Contents
Question & Answer for PRC‐012‐2 ............................................................................................................................ 2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ........................... 2
2. Why is the five year evaluation of Requirement R4 assigned to the Planning Coordinator? ............................ 2
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ......... 3
4. Why do RAS need to be reviewed and approved by a group other than the RAS‐entity? ................................ 3
5. What is required for RAS “single component failure” and why? ....................................................................... 3
6. What is required for RAS “inadvertent operation” and why? ........................................................................... 4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ............................................................................................................................................................. 5
8. Why are RAS classifications not recognized in the standard? ........................................................................... 5
9. What constitutes a functional modification of a RAS? ...................................................................................... 6
Attachment A – Project Roster…………………………………………………………………………………………………………………………….7
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
Question & Answer | February 2016
1
Question & Answer for PRC-012-2
The Project 2010‐05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC‐012‐2.
1.
Why is the Remedial Action Scheme (RAS) review assigned to the
Reliability Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk‐Power System. The NERC white paper suggested
Reliability Coordinators (RCs) and Planning Coordinators (PCs) for RAS‐review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best‐suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest‐area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. The Wide Area purview better facilitates
the evaluation of interactions among separate RAS, as well as interactions among RAS and other
protection and control systems. The selection of the RC also minimizes the possibility of a conflict
of interest that could exist because of business relationships among the RAS‐entity, Planning
Coordinator, Transmission Planner, or other entities involved in the planning or implementation
of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain
objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2.
Why is the five year evaluation of Requirement R4 assigned to the
Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least once every five full
calendar years to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February 2015
2
3.
Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP‐1‐3 Requirement R13 requires Balancing Authorities (BA) and Transmission Operators (TOP)
to perform operational reliability assessments (e.g., real time contingency analysis (RTCA), day‐
ahead, seasonal) that include data describing new or degraded RAS. In addition, IRO‐005‐4
requires RCs to share any pertinent data, such as data from RAS, with potentially affected BAs
and TOPs. Operating horizon assessments that include RAS are already required by other
standards, so an additional requirement duplicating that effort is not necessary.
TPL‐001‐4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near‐term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short‐term (annual) planning horizon assessments are already
required by the TPL‐001‐4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS‐entities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why?
The existing PRC‐012‐1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.5 and
Attachment 1 of PRC‐012‐2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February 2015
3
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
Using alternative automatic actions to back up failures of single RAS components.
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re‐dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review processes and designated as
Type 3 in NPCC or Local Area Protection Scheme (LAPS) in WECC will be recognized as limited
impact. When appropriate, new or functionally modified RAS implemented after the effective
date of this standard will be designated as limited impact by the Reliability Coordinator during
the RAS review process. Limited impact schemes are not subject to the single component failure
aspect of Requirement R4, Part 4.1.5.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC‐012‐1 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0) as that required of the contingency for which
it was designed and not exceed TPL‐003‐0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.4 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL‐001‐4 or for System conditions
not defined in TPL‐001‐4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.4.1 – 4.1.4.5, which are the
performance requirements common to all planning events P0–P7.
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February 2015
4
date of this standard that has been through the regional review processes and designated as
Type 3 in NPCC or LAPS in WECC will be recognized as limited impact. When appropriate, new or
functionally modified RAS implemented after the effective date of this standard will be
designated as limited impact by the Reliability Coordinator in conjunction with the RAS review
process. Limited impact schemes are not subject to the single component malfunction aspect of
Requirement R4, Part 4.1.4.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific System configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post‐Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS‐SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC‐012‐1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.5 and Attachment 1, item III.4
of PRC‐012‐2 that relates to single component failure; consequently, there is no need to have a
formal classification for this purpose.
Similarly, the standard drafting team concluded that the SPCS‐SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC‐
012‐1, and problematic due to the difficulty of drawing a universally satisfactory delineation in
generally worded classification criteria. Within the RAS review process of PRC‐012‐2, there is a
provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation,
angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the regional
review processes and designated as Type 3 in NPCC or LAPS in WECC will be recognized as limited
impact. When appropriate, new or functionally modified RAS implemented after the effective
date of this standard will be designated as limited impact by the Reliability Coordinator in
conjunction with the RAS review process.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February 2015
5
9.
What constitutes a functional modification of a RAS?
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality of
existing components
• Changes to RAS logic beyond correcting existing errors
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS‐entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor that carries RAS communication when such changes may be
important to the timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component, or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation logic.
The Supplemental Material section of Reliability Standard PRC‐012‐2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February 2015
6
Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles‐Eric Langlois
Hydro‐Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February 2015
7
Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
November February 20165
Table of Contents
Question & Answer for PRC‐012‐2 ............................................................................................................................ 2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ........................... 2
2. Why is the 60 five month year evaluation of Requirement R4 assigned to the Planning Coordinator? ........... 2
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ......... 3
4. Why do RAS need to be reviewed and approved by a group other than the RAS‐entity? ................................ 3
5. What is required for RAS “single component failure” and why? ....................................................................... 3
6. What is required for RAS “inadvertent operation” and why? ........................................................................... 4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ............................................................................................................................................................. 5
8. Why are RAS classifications not recognized in the standard? ........................................................................... 5
9. What constitutes a functional modification of a RAS? .................................................................................... 76
Attachment
A
–
Roster…………………………………………………………………………………………………………………………….87
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
Question & Answer | NovemberFebruary 20165
Project
1
Question & Answer for PRC-012-2
The Project 2010‐05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC‐012‐2.
1.
Why is the Remedial Action Scheme (RAS) review assigned to the
Reliability Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk‐Power System. The NERC white paper suggested
Reliability Coordinators (RCs) and Planning Coordinators (PCs) for RAS‐review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best‐suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest‐area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. The Wide Area purview better facilitates
the evaluation of interactions among separate RAS, as well as interactions among RAS and other
protection and control systems. The selection of the RC also minimizes the possibility of a conflict
of interest that could exist because of business relationships among the RAS‐entity, Planning
Coordinator, Transmission Planner, or other entities involved in the planning or implementation
of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain
objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2.
Why is the five year60 month evaluation of Requirement R4
assigned to the Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least once every 60 five
full calendar months years to verify the continued effectiveness and coordination of the RAS, its
inadvertent operation performance, and the performance for a single component failure. The
items that must be addressed in the evaluations include: 1) RAS mitigation of the System
condition(s) or event(s) for which it was designed; 2) RAS avoidance of adverse interactions with
other RAS and with protection and control systems; 3) the impact of inadvertent operation; and
4) the impact of a single component failure. The evaluation of these items involves modeling and
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
2
studying the interconnected transmission system, similar to the planning analyses performed by
PCs.
3.
Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP‐1‐3 Requirement R13 requires Balancing Authorities (BA) and Transmission Operatorswners
(TOP) to perform operational reliability assessments (e.g., real time contingency analysis (RTCA),
day‐ahead, seasonal) that include data describing new or degraded RAS. In addition, IRO‐005‐4
requires RCs to share any pertinent data, such as data from RAS, with potentially affected BAs
and TOPs. Operating horizon assessments that include RAS are already required by other
standards, so an additional requirement duplicating that effort is not necessary.
TPL‐001‐4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near‐term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short‐term (annual) planning horizon assessments are already
required by the TPL‐001‐4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS‐entities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why?
The existing PRC‐012‐1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.4 5
and Attachment 1 of PRC‐012‐2 reaffirms this objective by stating: “a single component failure in
the RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL‐001‐4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
3
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
Using alternative automatic actions to back up failures of single RAS components.
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re‐dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review processes and designated as
Type 3 in NPCC, Type 2 in ERCOT, or Local Area Protection Scheme (LAPS)LAPS in WECC will be
recognized as limited impact. When appropriate, new or functionally modified RAS implemented
after the effective date of this standard will be designated as limited impact by the Reliability
Coordinator during the RAS review process. Limited impact schemes are not subject to the single
component failure aspect of Requirement R4, Part 4.1.45.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC‐012‐1 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL‐001‐0, TPL‐002‐0, and TPL‐003‐0) as that required of the contingency for which
it was designed and not exceed TPL‐003‐0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.3 4 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL‐001‐4 or for System conditions
not defined in TPL‐001‐4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.34.1 – 4.1.34.5, which are the
performance requirements common to all planning events P0–P7.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
4
Within the RAS review process of PRC‐012‐2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review processes and designated as
Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be recognized as limited impact. When
appropriate, new or functionally modified RAS implemented after the effective date of this
standard will be designated as limited impact by the Reliability Coordinator in conjunction with
the RAS review process. Limited impact schemes are not subject to the single component
malfunction aspect of Requirement R4, Part 4.1.34.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific System configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post‐Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS‐SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC‐012‐1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.4 5 and Attachment 1, item
III.4 of PRC‐012‐2 that relates to single component failure; consequently, there is no need to have
a formal classification for this purpose.
Similarly, the standard drafting team concluded that the SPCS‐SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC‐
012‐1, and problematic due to the difficulty of drawing a universally satisfactory delineation in
generally worded classification criteria. Within the RAS review process of PRC‐012‐2, there is a
provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation,
angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the regional
review processes and designated as Type 3 in NPCC, Type 2 in ERCOT, or LAPS in WECC will be
recognized as limited impact. When appropriate, new or functionally modified RAS implemented
after the effective date of this standard will be designated as limited impact by the Reliability
Coordinator in conjunction with the RAS review process.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
5
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
6
9.
What constitutes a functional modification of a RAS?
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in‐kind replacement; i.e., match the original functionality in‐
kind replacement of existing components
• Changes to RAS logic beyond correcting existing errorserror correcting
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS‐entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor that carries RAS communication when such changes may be
important to the timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component, or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation logic.
The Supplementalry Material section of Reliability Standard PRC‐012‐2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
7
Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles‐Eric Langlois
Hydro‐Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | November February 2015
8
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Formal Comment Period Open through March 18, 2016
Now Available
A 45-day formal comment period for PRC-012-2 – Remedial Action Schemes is open through 8 p.m.
Eastern, Friday, March 18, 2016.
The drafting team appreciates the feedback stakeholders provided on the previous posting. The drafting
team considered all of the comments and revised the standard and its implementation plan accordingly,
making clarifying changes to both documents. Responses to the most prevalent comments received and
a summary of the changes to the documents are located in the Consideration of Comments document
posted on the project page as responses to individual comments are not required for a failed additional
ballot in accordance with sections 4.12 and 4.13 of the Standards Process Manual. The drafting team will
respond to all individual comments received in the last additional ballot conducted (the passing ballot)
prior to conducting the Final Ballot. If you have a specific comment that you would like to discuss, please
contact the Standards Developer, Al McMeekin at 404-446-9675 or via email Al McMeekin. Please
provide your comment, your contact information, and a convenient date and time for a discussion.
The drafting team is soliciting comments and feedback on the revised standard and its implementation
plan.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted
on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
An additional ballot and a non-binding poll of the associated Violation Risk Factors and Violation Severity
Levels will be conducted March 9-18, 2016.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2010-05.3
Phase 3 of Protection Systems: RAS | February - March, 2016
2
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2
Formal Comment Period Open through March 18, 2016
Now Available
A 45-day formal comment period for PRC-012-2 – Remedial Action Schemes is open through 8 p.m.
Eastern, Friday, March 18, 2016.
The drafting team appreciates the feedback stakeholders provided on the previous posting. The drafting
team considered all of the comments and revised the standard and its implementation plan accordingly,
making clarifying changes to both documents. Responses to the most prevalent comments received and
a summary of the changes to the documents are located in the Consideration of Comments document
posted on the project page as responses to individual comments are not required for a failed additional
ballot in accordance with sections 4.12 and 4.13 of the Standards Process Manual. The drafting team will
respond to all individual comments received in the last additional ballot conducted (the passing ballot)
prior to conducting the Final Ballot. If you have a specific comment that you would like to discuss, please
contact the Standards Developer, Al McMeekin at 404-446-9675 or via email Al McMeekin. Please
provide your comment, your contact information, and a convenient date and time for a discussion.
The drafting team is soliciting comments and feedback on the revised standard and its implementation
plan.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted
on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
An additional ballot and a non-binding poll of the associated Violation Risk Factors and Violation Severity
Levels will be conducted March 9-18, 2016.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2010-05.3
Phase 3 of Protection Systems: RAS | February - March, 2016
2
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
PRC-012-2
Additional Ballot and Non-binding Poll Results
Now Available
A formal comment period and additional ballot for PRC-012-2 – Remedial Action Schemes, as well as a
non-binding poll of the associated Violation Risk Factors and Violation Severity Levels concluded 8 p.m.
Eastern, Friday, March 18, 2016.
The voting statistics are listed below, and the Ballot Results page provides detailed results for the ballot
and non-binding poll.
PRC-012-2
Non-binding Poll
Quorum / Approval
Quorum / Supportive
Opinions
75.55% / 78.87%
77.52% / 80.00%
Next Steps
The drafting team will consider all responses received during the comment period and determine the
next steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Comment Report
Project Name:
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS) | PRC-012-2
Comment Period Start Date:
2/3/2016
Comment Period End Date:
3/18/2016
Associated Ballots:
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 AB 3 ST
2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 Non-binding Poll AB 3 NB
There were 43 sets of responses, including comments from approximately 41 different people from approximately 39 companies
representing 8 of the Industry Segments as shown in the table on the following pages.
Questions
1. PRC-012-2: Requirements R4 and R6, Attachments 1 and 2, and the Supplemental Material section of the standard were modified for clarity
and completeness. Do you agree with the proposed changes? If no, please provide the basis for your disagreement and an alternate
proposal.
2. Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to provide for the initial consideration of limited
impact RAS, and to clarify that the initial obligation under Requirement R9 for a Reliability Coordinator that does not have a RAS database is
to establish a RAS database by the effective date of PRC-012-2. Do you agree with the revised Implementation Plan? If no, please provide the
basis for your disagreement and an alternate proposal.
Organization
Name
ACES Power
Marketing
Southwest
Power Pool,
Inc. (RTO)
Name
Ben Engelby
Segment(s)
Region
6
Charles Yeung 2
Group Name
Group Member
Name
ACES
Ellen Watkins
Standards
Collaborators - Shari Heino
PRC-012-2
Project
Ginger Mercier
SPP RE
SRC-ISONE
Group
Member
Organization
Group
Member
Segment(s)
Group Member
Region
ACES Power
Marketing
1
SPP RE
ACES Power
Marketing
1,5
Texas RE
ACES Power
Marketing
1,3
SERC
Mark Ringhausen ACES Power
Marketing
3,4
RF
Caitlin Schiebel
ACES Power
Marketing
4
RF
John Shaver
ACES Power
Marketing
1,4,5
WECC
Bill Hutchison
ACES Power
Marketing
1
SERC
Scott Brame
ACES Power
Marketing
3,4,5
SERC
Chip Koloini
ACES Power
Marketing
5
SPP RE
Bill Hutchison
ACES Power
Marketing
1
SERC
Charles Yeung
Southwest
Power Pool,
Inc. (RTO)
2
SPP RE
Ben Li
Southwest
Power Pool,
Inc. (RTO)
2
NPCC
Ali Miremadi
Southwest
Power Pool,
Inc. (RTO)
2
WECC
Greg Campoli
Southwest
Power Pool,
Inc. (RTO)
2
NPCC
Liz Axson
Southwest
Power Pool,
Inc. (RTO)
2
Texas RE
Lori Spence
Southwest
Power Pool,
Inc. (RTO)
2
MRO
Mark Holman
Southwest
Power Pool,
Inc. (RTO)
2
RF
Public Service Christy Koncz
Enterprise
Group
Duke Energy
SERC
Reliability
Corporation
MRO
Colby Bellville
David Greene
Emily
Rousseau
1,3,5,6
1,3,5,6
10
1,2,3,4,5,6
NPCC,RF
PSEG
FRCC,RF,SERC Duke Energy
SERC
MRO
SERC DRS
Tim Kucey
Public Service 5
Enterprise
Group
RF
Karla Jara
Public Service 6
Enterprise
Group
RF
Joseph Smith
Public Service 1
Enterprise
Group
RF
Jeffrey Mueller
Public Service 3
Enterprise
Group
RF
Doug Hils
Duke Energy
1
RF
Lee Schuster
Duke Energy
3
FRCC
Dale Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Mei Li
SERC
Reliability
Corporation
1
SERC
Zakia El Omari
SERC
Reliability
Corporation
1
SERC
Wade Richards
SERC
Reliability
Corporation
1
SERC
Bob Jones
SERC
Reliability
Corporation
1
SERC
John O'Connor
SERC
Reliability
Corporation
1
SERC
John Sullivan
SERC
Reliability
Corporation
1
SERC
Tom Cain
SERC
Reliability
Corporation
1
SERC
Venkat Kolluri
SERC
Reliability
Corporation
1
SERC
MRO
3,4,5,6
MRO
MRO
1
MRO
MRO
1,3,5
MRO
MRO-NERC
Joe Depoorter
Standards
Review Forum Chuck Lawrence
(NSRF)
Chuck Wicklund
Seattle City
Light
Southern
Company Southern
Company
Services, Inc.
Ginette
Lacasse
1,3,4,5,6
Pamela Hunter 1,3,5,6
WECC
SERC
Seattle City
Light Ballot
Body
Southern
Company
Dave Rudolph
MRO
1,3,5,6
MRO
Kayleigh
Wilkerson
MRO
1,3,5,6
MRO
Jodi Jenson
MRO
1,6
MRO
Larry Heckert
MRO
4
MRO
Mahmood Safi
MRO
1,3,5,6
MRO
Shannon Weaver
MRO
2
MRO
Mike Brytowski
MRO
1,3,5,6
MRO
Brad Perrett
MRO
1,5
MRO
Scott Nickels
MRO
4
MRO
Terry Harbour
MRO
1,3,5,6
MRO
Tom Breene
MRO
3,4,5,6
MRO
Tony Eddleman
MRO
1,3,5
MRO
Amy Casucelli
MRO
1,3,5,6
MRO
Pawel Krupa
Seattle City
Light
1
WECC
Dana Wheelock
Seattle City
Light
3
WECC
Hao Li
Seattle City
Light
4
WECC
Bud (Charles)
Freeman
Seattle City
Light
6
WECC
Mike haynes
Seattle City
Light
5
WECC
Michael Watkins
Seattle City
Light
1,3,4
WECC
Faz Kasraie
Seattle City
Light
5
WECC
John Clark
Seattle City
Light
6
WECC
Robert A.
Schaffeld
Southern
Company Southern
Company
Services, Inc.
1
SERC
R. Scott Moore
Southern
Company Southern
Company
Services, Inc.
3
SERC
Dominion Dominion
Resources,
Inc.
Northeast
Power
Coordinating
Council
Randi Heise
Ruida Shu
5
1,2,3,4,5,6,7
Dominion RCS
NPCC
William D. Shultz
Southern
Company Southern
Company
Services, Inc.
5
SERC
John J. Ciza
Southern
Company Southern
Company
Services, Inc.
6
SERC
Larry Nash
Dominion Dominion
Resources,
Inc.
1
SERC
Louis Slade
Dominion Dominion
Resources,
Inc.
6
SERC
Connie Lowe
Dominion Dominion
Resources,
Inc.
3
RF
Randi Heise
Dominion Dominion
Resources,
Inc.
5
NPCC
Northeast
Power
Coordinating
Council
1
NPCC
Guy Zito
Northeast
Power
Coordinating
Council
NA - Not
Applicable
NPCC
Brian Shanahan
Northeast
Power
Coordinating
Council
1
NPCC
Rob Vance
Northeast
Power
Coordinating
Council
1
NPCC
Mark J. Kenny
Northeast
Power
Coordinating
Council
1
NPCC
Gregory A.
Campoli
Northeast
Power
2
NPCC
RSC No HQ
Paul Malozewski
and Dominion
Coordinating
Council
Randy MacDonald Northeast
Power
Coordinating
Council
2
NPCC
Wayne Sipperly
Northeast
Power
Coordinating
Council
4
NPCC
David
Ramkalawan
Northeast
Power
Coordinating
Council
4
NPCC
Glen Smith
Northeast
Power
Coordinating
Council
4
NPCC
Brian O'Boyle
Northeast
Power
Coordinating
Council
5
NPCC
Brian Robinson
Northeast
Power
Coordinating
Council
5
NPCC
Bruce Metruck
Northeast
Power
Coordinating
Council
6
NPCC
Alan Adamson
Northeast
Power
Coordinating
Council
7
NPCC
Michael Jones
Northeast
Power
Coordinating
Council
3
NPCC
Michael Forte
Northeast
Power
Coordinating
Council
1
NPCC
Kelly Silver
Northeast
Power
Coordinating
Council
3
NPCC
Southwest
Power Pool,
Inc. (RTO)
Shannon
Mickens
2
SPP RE
Brian O'Boyle
Northeast
Power
Coordinating
Council
5
NPCC
Edward Bedder
Northeast
Power
Coordinating
Council
1
NPCC
David Burke
Northeast
Power
Coordinating
Council
3
NPCC
Peter Yost
Northeast
Power
Coordinating
Council
4
NPCC
Helen Lainis
Northeast
Power
Coordinating
Council
2
NPCC
Michele Tondalo
Northeast
Power
Coordinating
Council
1
NPCC
Kathleen
Goodman
Northeast
Power
Coordinating
Council
2
NPCC
Silvia Parada
Mitchell
Northeast
Power
Coordinating
Council
4
NPCC
SPP
Shannon Mickens Southwest
Standards
Power Pool,
Inc. (RTO)
Review Group
2
SPP RE
Jason Smith
Southwest
Power Pool,
Inc. (RTO)
2
SPP RE
Patrick McPhail
Southwest
Power Pool,
Inc. (RTO)
1
SPP RE
Robert Hirchak
Southwest
Power Pool,
Inc. (RTO)
1,3,5,6
SPP RE
Jamison Cawley
Southwest
Power Pool,
Inc. (RTO)
1,3,5
MRO
Greg Hill
Southwest
Power Pool,
Inc. (RTO)
1,3,5
MRO
1. PRC-012-2: Requirements R4 and R6, Attachments 1 and 2, and the Supplemental Material section of the standard were modified for clarity
and completeness. Do you agree with the proposed changes? If no, please provide the basis for your disagreement and an alternate
proposal.
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RF
Answer
No
Document Name
Comment
We object to Generator Owners having a primary role in this standard. The nature of a RAS is not to protect individual generators, for these must have
adequate protection for faults or abnormal operating situations. The RAS is typically designed to maintain the reliability of a significant area of the
overall power system. As such, the Transmission Owner is the best entity to ensure that RAS are employed correctly. Unlike the GO, the TO has the
“wide-area” scope of monitoring and system responsibility.
The draft standard is deficient due to the patchwork nature of responsibility for a RAS, especially when there are multiple Owners of portions of the
RAS. There needs to be a single RAS Owner that has overall responsibility for ensuring the requirements of PRC
‐01
should be a Transmission Owner, not a Generator Owner. The TO (RAS Owner) should take the lead in developing the data needed for requirements
R1 and R3, with the other RAS entities being required to provide data and equipment modifications as needed. Requirements R5 through R8 should
apply to the RAS-Owner, not the RAS entities. The RAS Owner should be the point of contact with the Planning Coordinator/Reliability Coordinator,
with the RAS entities having responsibility to collaborate with the RAS Owner as needed.
Likes
1
Dislikes
U.S. Bureau of Reclamation, 5, Doot Erika
0
Response
Daniel Mason - City and County of San Francisco - 5
Answer
No
Document Name
Comment
The Standards identifies a RAS-entity as "the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS". In some
cases this "part" could be as limited as a sensing device providing input to another entity's RAS logic and interupting devices. For those RAS-entities
that find themselves in that situation, providing the information identified in Attachments 1 and 2 is not appropriate. The Standard should clear
up reporting responsibilities for such minor RAS-entities, perhaps by employ the concept of a "RAS Reporting Agent" for each RAS.
Likes
0
Dislikes
Response
0
Gul Khan - Gul Khan
Answer
No
Document Name
Comment
Oncor does not currently provide the documents mentioned on page 21 of the PRC-012-2 draft 3 standard bullet # 1. We can provide a simple map of
where a RAS will be located but if we are being requested to provide relay functional drawings or detailed 3 line schematics we won’t have those
drawings developed until the RAS is approved. Additionally even if we have the documents and do send it to ERCOT, we have a confidentiality concern
as these files will get posted in a public information database. We have touched base with our RC, ERCOT, and they agree that the process we are
doing today is satisfactory and is working. Hence we do not see a need to provide the documentation in attachment 1. The additional information should
be optional.
Likes
0
Dislikes
0
Response
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
SRP appreciates the efforts of the SDT and recommends the removal of the language in the attachments that refers to a “checklist”. Initial drafts of the
attachments were checklists. What is presented cannot be described as a “checklist”. SRP believes this language will create confusion.
SRP further recommends removing the definition for “limited impact” from the footer of the attachment. If this is to be a definition, it should be defined in
the NERC Glossary of Terms.
SRP recommends the removal of the definition for “Functionally Modified” from the footer of the documents. Capitalized terms are to be part of the
NERC Glossary of Terms and should not be located outside of that body of work.
Likes
0
Dislikes
0
Response
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Answer
Document Name
No
Comment
AZPS appreciates the efforts of the Standard Drafting Team (SDT) to date and makes the following comments:
The materials state that a limited impact RAS is “determined by the RC”. AZPS suggests modifying the language to “…limited impact RAS as
determined by the RC based on predefined regionally appropriate criteria.” An RC's determination of whether a RAS is limited impact should include an
evaluation of the potential impacts of the RAS and should reference pre-defined regionally appropriate criteria defined through a regionally accepted
process (e.g. via the RASRC in WECC).
The Technical Justification section directed to Limited Impact states, “The reviewing RC is the sole arbiter for determining whether a RAS qualifies for
the limited impact designation.” While not in direct conflict, AZPS believes that some entities may misinterpret the modified language as limiting the
“The RC from requesting assistance in RAS reviews from other parties such as the PC(s) or regional technical groups (e.g., Regional Entities)” as
provided for earlier in the document. AZPS requests that the “sole arbiter” sentence be clarified to address this concern.
R4.1.3 is currently amended to state “for limited impact RAS, the inadvertent operation of the RAS or the failure of the RAS to operate does not cause
or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations.”
The word “contribute” should be removed because it reduces clarity to the standard. The term “contribute” is too broad and creates challenges to
precisely evaluate.
AZPS appreciates the DT addressing the concern of cases where a RAS crosses one or more RC Area boundaries, each affected RC is responsible for
conducting either individual reviews or participating in a coordinated review by adding language in the appropriate rational and Supplemental Material
sections. AZPS requests the SDT consider if this information would be more impactful as a footnote to the requirements themselves.
Likes
0
Dislikes
0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
No
Document Name
Project 2010-05 3 PRC-012-2L RAS Seattle City Light Comments Ballot 2016 March 16.pdf
Comment
Need to clarify roles and responsibilities for those RAS that are multi-jurisdictional. See Attached comments
Likes
0
Dislikes
0
Response
Christy Koncz - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG
Answer
No
Document Name
PSEG Comments_2010-05.3_3-17-2016.doc
Comment
Requirement 1 – There are no clear lines of responsibility for jointly owned RASs.
The concept of a RAS-entity causes RAS-entity causes confusion for entities that have joint ownership of a RAS. While the SDT recognizes this issue
by stating: “ Ideally, when there is more than one RAS
r‐entity
a RAS,
fo the RAS
‐entities w
Attachment 1to the reviewing RC”. While PSEG agrees with the intent of this statement, it is included in the “Rationale” section of the draft standard
and therefore that language will not be incorporated into the final standard. Furthermore, PSEG believes that PSEG that the language of R1 would still
require each RAS entity to submit all information in Attachment 1to the Reliability Coordinator, which is inconsistent with the Paragraph 81 effort and the
Reliability Assurance Initiative. PSEG believes such intent could be incorporated in to R1 as follows:
R1. Prior to placing a new or functionally modified RAS in
‐service
the
information
or retiring
identified
an existin
in
Attachment 1 for review to the Reliability Coordinator(s) where the RAS is located. If there are multiple RAS-entities, the entities may delegate a single
mutually agreeable RAS-entity to submit Attachment 1 on their behalf.
PSEG wishes to note that such language would not be useful in situations where the one or more of the RAS-entities that jointly own a RAS do not want
to cooperate or cannot agree upon a single lead entity. Additionally, PSEG believes that a single entity (either the Reliability Coordinator or the Planning
Coordinator) should be responsible for coordinating the RAS entities.
Attachment 1 – Attachment 1 should have defined roles for the Planning Coordinator (PC) or Transmission Planner (TP).
Since the requirement for new and revised remedial action schemes are likely to be initiated by the results of Transmission system planning
performance assessments done by the TP or PC in compliance with TPL-001-4, one of those entities would be best suited to perform many of the
activities listed under section II of Attachment 1.
Furthermore, the technical studies that are required by Attachment 1 should not be performed individually by each RAS-entity because they do not
have the skills or tools available to perform such analyses. For example, if an independent generator is asked by its RC to implement a run-back
scheme to resolve a stability issue, it is unlikely that that entity would have to tools available to provide the information required under Attachment 1,
item II.6.
Rather, PSEG recommends that the RAS-entities’ PC or (TP) conduct the assessment of the System performance of a proposed new, modified, or
retired RAS. Under this construct a RAS-entity implementing a new, modified, or retired RAS would submit an application under R1 containing general
information as well as details concerning the proposed components and logic of the RAS to its TP or PC and to other RAS-entities that would participate
in the RAS The PC or TP in turn would conduct the assessment of the proposed RAS to determine if the proposed RAS resolves the System
performance issues, and forward that information to the RC for consideration under Requirement 2.
Likes
2
Dislikes
Pragna Pulusani, N/A, Pulusani Pragna; PSEG - PSEG Energy Resources and Trade LLC, 6, Jara Karla
0
Response
Greg Davis - Greg Davis
Answer
No
Document Name
Comment
GTC Background:
There are multiple registered Planning Coordinators and jointly shared transmission system in GTC’s Planning Area and it is important for each PC in
the area to be notified prior to placing new or functionally modified RAS in-service or retiring an existing RAS. Equally as important, is for each PC in
the area to be notified if CAP actions or timetables change when the CAP is completed pursuant to CAPs developed for R6. GTC’s proposed
considerations listed below are focused on mitigating operational and compliance risks associated with awareness and knowledge of new or functionally
modified RAS where there are multiple registered PCs in a common RC Area.
R7.3:
Although R4.2 requires each impacted TP and PCs to be notified of results of a RAS evaluation, there is not a similar method for any impacted TP
and/or PC to be notified in which a RAS was evaluated with identified deficiencies pursuant to CAPs developed for R6; nor when or if CAP is
implemented in a timely manner or if timetables change. We propose including the phrase “and Planning Coordinators within the RAS-entity’s area” in
R7.3, which would read as follows: “Notify each reviewing Reliability Coordinator and Planning Coordinators within the RAS-entity’s area, if CAP
actions or timetables change and when the CAP is completed.”
R9:
Even though it seems implied in R9 that the RAS database containing all pertinent data will be made available to impacted PCs and/or TPs in the RCs
area, it is unclear. GTC proposes the following new requirement to compliment the obligations of the Planning Coordinator under requirement R4 if the
aforementioned proposed changes to R7.3 are not adopted by the SDT.
R10 (proposed new requirement): Each Reliability Coordinator shall provide each Planning Coordinator in their Reliability Coordinator area a copy of the
RAS database maintained in accordance with R9, at least once every twelve full calendar months.
R4.1.5:
Since a RAS is only required when the performance requirements of TPL-001-4 will not be met, is R4.1.5 essentially mandating redundancy for all RAS
components? What does a single component failure constitute under Requirement R 4.1.5?
Clarification of limited impact RAS:
SERC DRS suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS considered
to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be experienced by just
one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or unreliable BES, and we do not
believe that this should remove an RAS from limited impact consideration.
Likes
0
Dislikes
0
Response
Ben Engelby - ACES Power Marketing - 6, Group Name ACES Standards Collaborators - PRC-012-2 Project
Answer
No
Document Name
Comment
1. RAS-entity causes confusion for entities that have joint ownership of a RAS. We recommend the SDT develop guidance to support the
requirements and expectations for joint owners to meet compliance. For RAS with multiple RAS-entities, who is responsible for overall
coordination to assure complete and consistent data submittals in order to meet compliance with this standard?
2. For R2, we remain concerned by the term “mutually agreeable” and how it will be applied.
3. Why did the SDT give the RC the authority to determine “limited impact” RAS without providing objective criteria or guidelines? The SDT cited
Local Area Protection Scheme (LAPS) in WECC and the Type 3 designation in NPCC. What about the other regions? There should be a
specific set of parameters for the RC to make a decision. We suggest developing continent-wide criteria for determining limited impact RAS
and not referring to only two regional approaches.
4. Why does the SDT include “limited impact” RAS as being applicable to the standard? If it has a limited impact, then it should not apply at
all. This proposal by the SDT is contrary to the past two years of NERC’s RAI and RBR initiatives focusing on HIGH RISK activities. By
definition, “limited impact” should not matter for BES reliability. The limited impact designation creates unnecessary compliance burdens
without a clear benefit to increased reliability of the BES.
Likes
0
Dislikes
0
Response
Teresa Czyz - Oglethorpe Power Corporation - 5
Answer
No
Document Name
Comment
OPC agrees with GTC's comments:
There are multiple registered Planning Coordinators and jointly shared transmission system in GTC’s Planning Area and it is important for each PC in
the area to be notified prior to placing new or functionally modified RAS in-service or retiring an existing RAS. Equally as important, is for each PC in
the area to be notified if CAP actions or timetables change when the CAP is completed pursuant to CAPs developed for R6. GTC’s proposed
considerations listed below are focused on mitigating operational and compliance risks associated with awareness and knowledge of new or functionally
modified RAS where there are multiple registered PCs in a common RC Area.
R7.3:
Although R4.2 requires each impacted TP and PCs to be notified of results of a RAS evaluation, there is not a similar method for any impacted TP
and/or PC to be notified in which a RAS was evaluated with identified deficiencies pursuant to CAPs developed for R6; nor when or if CAP is
implemented in a timely manner or if timetables change. We propose including the phrase “and Planning Coordinators within the RAS-
entity’s[JSS1] area” in R7.3, which would read as follows: “Notify each reviewing Reliability Coordinator and Planning Coordinators within the RASentity’s area, if CAP actions or timetables change and when the CAP is completed.”
R9:
Even though it seems implied in R9 that the RAS database containing all pertinent data will be made available to impacted PCs and/or TPs in the RCs
area, it is unclear. GTC proposes the following new requirement to compliment the obligations of the Planning Coordinator under requirement R4 if the
aforementioned proposed changes to R7.3 are not adopted by the SDT.
R10 (proposed new requirement): Each Reliability Coordinator shall provide each Planning Coordinator in their Reliability Coordinator area a copy of the
RAS database maintained in accordance with R9, at least once every twelve full calendar months.
R4.1.5:
Since a RAS is only required when the performance requirements of TPL-001-4 will not be met, is R4.1.5 essentially mandating redundancy for all RAS
components? What does a single component failure constitute under Requirement R 4.1.5?
Clarification of limited impact RAS:
SERC DRS suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS considered
to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be experienced by just
one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or unreliable BES, and we do not
believe that this should remove an RAS from limited impact consideration.
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Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
No
Document Name
Comment
Requirement 4 of the standard puts the burden of performing the studies on the PC. PNM as a registered PA/PC doesn’t contest the assignment of the
requirement to the PC; however, the standard doesn’t guarantee that the PC will be provided with the data required to perform the assessment. PNM
proposes adding a requirement for the RAS entity to provide data required to assess the RAS within 30 calendar days of receiving approval from the RC
so that the PC can obtain the information required to adequately assess each scheme every five full calendar years. The information provided to the
RC in R5.2, R6, R7.3 would impact the R4 assessment; therefore, the PC should also be receiving this information.
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Jared Shakespeare - Peak Reliability - 1
Answer
No
Document Name
Comment
What is the required evaluation for the PC in R4? For the RC it is clear to follow Attachment 2 for the evaluation but the PC in R4 does not have any
explicit evaluation requirement. We recommend adding language that describes the PC adhering at a minimum, but not limited to, Attachment 2 for their
5 year evaluation.
Both R4.1.4 and Attachment 1, section III, item 4 use the same language, “a single component failure in the RAS, when the RAS is intended to operate
does not prevent the BES from meeting the same performance requirements (defined in Reliability Standard TPL
‐001
required for the events and conditions for which the RAS is designed.” Though similar language is used in the currently effective set of reliability
standards, it is confusing and unclear. We recommend providing examples in an application guideline as part of the standard itself that might help the
reader understand the meaning of and intent behind this language.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
No
Document Name
Comment
Duke Energy suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS considered
to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be experienced by just
one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or unreliable BES, and we do not
believe that this should remove an RAS from limited impact consideration.
Duke Energy also reiterates its concern regarding the compliance implications of potentially requiring the RC to be responsible for the technical
correctness of an RAS-entity’s information it provides in Attachment 1. An RC should only be held responsible for the “wide area purview” or conceptual
appropriateness of a new or functionally modified RAS, and not be held responsible for potential mistakes made by the RAS-entity during the process.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
No
Document Name
Comment
Would suggest the drafting team develop a Standards Authorization Request (SAR) for the term ‘limited impact’ and propose the term be added to the
NERC Glossary and Rules of Procedure (RoP) to promote consistency and clarity. During our current evaluation of this draft of the Standard and
RSAW, we are concerned that the Rationale Box information (page 5 of the Standard-next to the sentence) is not consistent with the Requirement R4
sub-part 4.1.3. Another concern is that we feel the sub-part states the proposed definition of ‘limited impact’ twice. At the first use, the term ‘limited
impact’ is stated with a footnote-4 “A RAS designated as ‘limited impact’ cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations” then this same
information is stated again after the term. We suggest the drafting team use some different language besides “verify the limited impact designation
remains applicable” which was stated in the Rationale Box in order to make it clear just what the SDT intends the reviewer to do.
Additionally, we interpret that in the RSAW (note to Auditor-Section Requirement R4) there is an attempt to define the term ‘Inadvertent operation’. If
this is the case, we would suggest the review panel/drafting team should develop a SAR for that particular term and propose that it be included in the
NERC Glossary of Terms and Rules of Procedure (RoP) as well as including that term in the Standard again to promote consistency and clarity.
For Requirement R6, we have a concern that the translation of the Rationale and Technical data (in the Standard) and the Note to Auditor information
(in the RSAW) may become lost. As we have evaluated both documents, it seems more evident that the Rationale and Technical information needs to
be included in the RSAW. This information has been included in the Standard to help provide a solid foundation to each Requirement to help support
the auditing process. However, this information isn’t included in the RSAW which leads to potential inconsistency in the auditing process. We feel that
both documents need to contain the same information in order to be properly aligned.
Finally, our last concern would be having all maintenance requirements implemented into one document. Currently, we agree that Requirement R8
pertains to performing maintenance associated with Functional Testing as well as verifying proper operation of non-protection system components
(system maintenance). However, we suggest moving Requirement R8 into the PRC-005 Standard for consistency in reference to maintenance
requirements.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
The list of qualifications for the designation of limited impact states that a limited impact RAS cannot cause or contribute to BES Cascading,
uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. The term angular instability needs
to be clarified further. Currently it implies that if the RAS was installed to prevent a 40 MW generator from becoming unstable, then it cannot be
designated as limited impact. The term should be qualified as follows: system angular instability. This would give the RC the leeway to judge that a
small unit going unstable would not negate the designation limited impact.
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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
ERCOT is supportive of the “limited impact” RAS designation, and is also supportive of a periodic evaluation of RAS to determine if these still qualify for
the limited impact designation. However, ERCOT disagrees with the language of requirement subpart 4.1.3.
Clarification on the intention of 4.1.3 in this context is requested. A Planning Coordinator (PC) with limited impact RAS (ex. a RAS set up to reduce BES
flows by ramping down or tripping generation) should be allowed discretion to utilize screening studies as a threshold test to determine the necessity of
evaluating a RAS for uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. For limited
impact RAS that only have local impacts, 4.1.3 as written requires costly and unnecessary studies. ERCOT suggests that the SDT consider imposing a
MW threshold for each interconnection below which the PC would be required to conduct only a power flow study. Alternatively, ERCOT requests
clarification—in either 4.1.3 itself or in the rationale—that the PC has discretion in the type of studies it can use to satisfy the evaluations required to
determine if the reliability impact of the RAS has changed over time.
ERCOT also asks for clarification on the “Supporting Documentation for RAS Review” in Attachment 1. The introductory statement in Attachment 1
implies that the Reliability Coordinator (RC) has discretion in determining exactly what information it would like to receive from an RAS-entity with the
statement “If an item on this list does not apply to a specific RAS, a response of “Not Applicable” for that item is appropriate.” The RAS-entity and the
RC typically work together to determine what is required to approve an SPS or a RAS. The RC’s discretion in determining what information a RAS-entity
must submit under Attachment 1 is sufficient for the evaluation of the RAS.
ERCOT suggests the SDT make the RC’s discretion explicit through the following language modification to the Attachment 1 introduction:
“The following checklist identifies important Remedial Action Scheme (RAS) information for each new or functionally modified RAS that the RAS-entity
must document and provide to the reviewing Reliability Coordinator(s) (RC), as required by the RAS-entity’s Reliability Coordinator”
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Andrew Pusztai - American Transmission Company, LLC - 1
Answer
No
Document Name
Comment
ATC has several recommendations for improvement or clarification on the draft Standard, for consideration by the SDT as listed below:
•
R4.1.3 and R4.1.4 – These requirements refer to ‘single component malfunction’ and ‘single component failure’ respectively. However, the
standard does not contain any identification or clarification of which types of components must be included and which may be excluded in RAS
evaluations. This deficiency could be addressed by including text in the Supplemental Material section under Requirement 4 that the drafting
team developed for a response in its Consideration of Comments for Draft 1 of PRC-012-2.
“An exhaustive list of components is not practical given the variety that could be applied in RAS design and implementation. See Item 4a in the
Implementation Section of Attachment 1 in the Supplemental Material section for typical RAS components for which redundancy may be
‐entity
into service
shouldand
have
which
a clear
wereunde
considered. The RAS
already present in the system before a RAS was installed. The RC will make the final determination regarding which components should be
regarded as RAS components during its review”.
•
R5 – This requirement does not obligate RAS-entities to provide their results of the operational performance analysis of a RAS event to
impacted Transmission Planners and Planning Coordinators. However, this action should be proposed in the Supplemental Material section.
•
R6 – This requirement does not obligate RAS-entities to provide their Corrective Action Plans to impacted Transmission Planners and Planning
Coordinators. However, this action should be proposed in the Supplemental Material section.
•
R8 - The purpose of Version 6 of PRC-005 was to consolidate all maintenance and testing of relays under one Standard. Having RAS testing
within PRC-012-2 would be contrary to that end. ATC proposes to address this concern as follows:
Functional testing of RAS (as stated in Requirement 8 of PRC-012-2) is a maintenance and testing activity that would be better included in the PRC-005
standard. The present PRC-005-6 Reliability Standard is the maintenance standard that replaces PRC-005-1, 008, 011 and 017 and was designed to
cover the maintenance of SPSs/RASs. However, the current Reliability Standard PRC-005-6 lacks intervals and activities related to non-protective
devices such as programmable logic controllers. ATC recommends that a requirement for maintenance and testing of non-protective RAS components
be added to a revision of PRC-005-6, rather than be an outlying maintenance requirement located in the PRC-012-2 Standard.
If the requirement is not removed and placed in PRC-005 standard, then we suggest that wording be added to R8 to refer the entity to meet the
maintenance and testing interval obligations in the latest version of the PRC-005 standard.
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Douglas Webb - Douglas Webb
Answer
No
Document Name
Comment
Kansas City Power & Light Company appreciates this opportunity to share its comments regarding concerns the company has with the proposed
revisions to the Standard.
As used in the proposed revisions to Standard PRC-012-2, the term “limited impact” creates an ambiguous enforceable provision and needs to be a
defined NERC Glossary term to establish a clear compliance threshold.
The Standard Drafting Team (SDT) is empowered by the NERC Standards Process Manual (SPM) to “…propose to add, modify, or retire a defined term
in conjunction with the work it is already performing.” SPM, Sec. 5 Preamble. We respectfully request the SDT exercise that authority to define “limited
impact” for the following reasons.
“Limited impact” establishes an enforceable provision: The proposed revisions use “limited impact” in the language of the Requirements and
attachments to the Standard that are incorporated by reference. By the regular use of the term, and the context in which it is used, a conclusion is easily
drawn: The term is material to the Standard and required to evaluate compliance and, ultimately, enforcement of the Standard.
“Limited impact” creates an uncertain compliance obligation: The term “limited impact” is undefined and ambiguous and, as such, creates
uncertainty in an entity’s compliance obligation. The word “limited” suggests a range of values. When used with “impact,” the range of values is used to
affect the determination of the degree of impact. The proposed revisions to the Standard seek to establish the range of values in multiple ways. First, by
referencing information found in the stated underlying source of the term, WECC and NPCC classification schemes; secondly, offering an explanation
what is intended by the term; third, explaining what the term is not intended to reflect; and, lastly, a lengthy discourse on the term, as found in the
Attachments. Taken together, all the information may seem to provide guidance as to the meaning of the term, “limited impact,” but in the end the term
remains undefined and creates a compliance obligation that is unclear and promotes a spectrum of interpretations as to what values fall within the
“limited” range.
Policy promotes relevant Regional Defined Terms be considered for the NERC Glossary Term: The NERC Standards Process Manual (SPM)
states:
“Some NERC Regional Entities have defined terms that have been approved for use in Regional Reliability Standards, and where the drafting team
agrees with a term already defined by a Regional Entity, the same definition should be adopted if needed to support a NERC Reliability Standard.” SPM
Sec. 5.1.
The proposed revisions to the Standard provide that the source of the term “limited impact” is taken from the WECC and NPCC classification schemes.
Whether the term is a regionally defined term by WECC and NPCC or not, the spirit of the SPM is to apply terms equally, that if a term is used by
Regional Entities in a North American Standard, then it is appropriate for the term be considered for adoption as a defined term to support that
Standard.
Below is a Catalog of the Term “limited impact” as used in Proposed PRC-012-2 Standard
The Standard’s language uses “limited impact” in Requirements R4 and R8, and multiple times in the three attachments that are incorporated by
reference in the Standard.
WECC and NPCC Classification Schemes—R4 Rationale cites to the WECC and NPCC classification schemes as how the “…limited impact
designation is modeled…;” Technical Justification for the term “limited impact” states, “Because the drafting team modeled the limited impact
designation after the WECC and NPCC classifications…”
Description of what the term, “limited impact,” is not—R4.1.3. Footnote to “limited impact.” See also Att. 1, Sec. I.4.g Footnote to “limited impact”; Att. 2,
Sec. I.6 Footnote to “limited impact”; Att. 3, Sec. 7 Footnote to “limited impact”; Technical Justifications for Attachment 1 Content Supporting
Documentation for RAS Review, Sec. I.4.g Footnote to “limited impact”; Technical Justifications for Attachment 3 Content, Sec. 7 Footnote to “limited
impact.”
“Limited impact” Citations in Standard—The use of the term “limited impact” in R4; R8; Att. 1, Sec. I.4.g; Att. 1, Sec. II.5; Att. 1, Sec. II.6; Att. 1, Sec.
III.4; Att. 2, Sec. I.6; Att. 2, Sec. I.7; Att. 2, Sec. II.2; Att. 3, Sec. 7; Supplemental Material, R4, R8; Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review, Sec. I.4.g, Sec. II.5, Sec. II.6, Sec. III.4; and Technical Justifications for Attachment 3 Content, Sec. 7.
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Oshani Pathirane - Oshani Pathirane
Answer
No
Document Name
Comment
Comment 1 - R4.1.5 - In TPL-001-4, loss of a single line due to a fault is “Single Contingency” (Category P1), but the failure of a breaker or protection
relay following that single contingency is recognized as “Multiple Contingency” (Category P4 and P5) and has a different performance requirement
compared to the initial P1 event. Similarly, the system performance following a RAS failure to operate after an event should not be required to meet the
exact same requirements as those for the original event.
Therefore, we suggest deleting 4.1.5 and instead revising 4.1.4 to say “Except for limited impact RAS, the possible inadvertent operation of the RAS,
resulting from any single RAS component malfunction, or a single component failure in the RAS, when the RAS is intended to operate, satisfies all of
the following:”
Comment 2 - R5.1 – The wording “participate” which is used in the R5.1 does not define accountability or a definite action. For consistency, we
suggest using verbiage similar to that used in PRC-004-4’s description of accountabilities in the case of owning Shared Protection Systems.
Comment 3 - R5.1.3 & R5.1.4 are related to performance of RAS and its impact on BES system. This assessment is better suitable for the PC or RC to
conduct
Comment 4 – In R5.2, in case of a RAS being owned by more than one RAS-Entity, it is unclear which RAS-Entity is accountable to communicate with
the RC and maintain evidence. The requirement needs to clearly identify who is accountable for what, similarly to how PRC-004-4 describes
accountabilities in case of Shared Protection System.
Comment 5 – Similar to R5, the wording “participate” used in R6 does not define accountability or a definite action. For consistency, we suggest using
verbiage similar to that used in PRC-004-4’s description of accountabilities in the case of owning Shared Protection Systems.
Comment 6 - Similar to comment R5 above, R6 does not clearly define accountabilities in the case of a RAS being owned by more than one RASEntity. In such case, which Entity is accountable to communicate with the RC and maintain evidences?
Comment 7 – It is unclear from the wording whether the RAS-entity would “Participate in analyzing the RAS operational performance” with the RC, or
only mutually agree upon a schedule for such activity with the RC.
Comment 8 - R8 is vague and subject to interpretation. There are references in the supplemental material that suggest maintenance checking all of the
logic in a PLC on a periodic basis is required and yet in PRC-005, it’s clear that there is no need to perform periodic maintenance on relay logic. For
monitored components, such as microprocessor relays, the “verification of settings [as] specified” in PRC-005 (i.e., performing a settings compare)
should be sufficient rather than implying that all logic needs to be re-verified. For RAS not designated as limited-impact, R8 does not distinguish
between monitored and unmonitored components of the RAS such as in PRC-005, which would allow a RAS-entity to have a 12-year maintenance
interval for monitored components.
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
Regarding R4:
BPA believes that limited impact RAS should not be singled out to be exempt from meeting the performance requirements.
While the level of review could be lower, BPA believes a “limited impact” RAS should still be designed such that failure or inadvertent operation of the
RAS does not have an adverse impact on an adjacent TP or PC beyond the performance criteria for which the system is planned.
Additionally, regarding R2:
BPA maintains that allowing an RC up to four months to complete the RAS review is longer than necessary and not in line with current practice, which
requires the information to be submitted to the RAS Reliability Subcommittee two weeks prior to the meeting where it will be reviewed and approved or
disapproved. Allowing four months could delay energization of new or functionally modified RAS by 14 weeks.
BPA also remains concerned by the term “mutually agreeable” and how it will be applied.
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Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
No
Document Name
RS--3-15-16--2010-05 3_PRC-012-2_Unofficial_Comment_Form_2016-03-18- Final.docx
Comment
As a general comment, HQT is in the view that PRC-012-2 should not address the details of how RAS entities should perform their analysis according
to requirement R8. Each RAS entity has systems operation applicability adapted to their particular topology and some systems cannot withstand
invasive actions (maintenance and testing activities) because of such topology. Therefore, PRC-012-2 requirements should allow a certain level of
flexibility to this effect, which HQT has commented further below.
Regarding comments specific to the wording of PRC-012-2 requirements, Footnote 2 in Attachment 1 is a definition, and it should be treated as
such. Also, the fourth bullet under footnote 2 reads “Changes to RAS logic beyond correcting existing errors” needs clarification. What are the existing
errors? The RAS should not have been approved if there were errors, and if it was approved with the errors then those errors might be preventing the
RAS from meeting its intended functionality. Suggest removing this bullet, and revising the second bullet to read: Changes to the logic that affects the
actions the RAS is designed to initiate. The preceding is also applicable to Footnote 4 on page 25 for Attachment 2. Footnote 3 on page 23, footnote 5
on page 25, and footnote 6 on page 27 are not needed because of the first comment above regarding Requirement R4.
In addition, on page 27 in the Supplemental Material Section, shouldn’t the Planning Coordinator, because of its wide-area view be included in
determining if a RAS can be designated limited impact? In the two paragraphs preceding Requirement R1 on page 29 of the Supplemental Material it
should be emphasized that the actions of the limited-impact RAS do not lead to the more severe BES consequences that would preclude a RAS from
being defined a limited-impact RAS. On page 34, same comment as in the preceding paragraph concerning “Changes to RAS logic beyond correcting
existing errors”. On page 34 of the Supplemental Material in the third paragraph under Requirement R4, shouldn’t the Planning Coordinator, because of
its wide-area view, be involved in the designation of a RAS as limited-impact?
Also, on page 45 for the Technical Justifications for Attachment 1 Content Supporting documentation for RAS Review, comments pertaining to footnote
8 the same as above for the comments regarding footnote 2.
HQT also has specific comments on requirements R5 and R8 as follows.
Firstly for NPCC, the Type ‘3’ should be written ‘III’. Also, VSL of R5 requests to ‘perform’ analysis. R5 mentioned only to ‘participate’. In the Rationale
section, at R4: references to Parts 4.1.3.1-4.1.3.5 should be corrected to 4.1.4.1-4.1.5. HQT is in the opinion that Lower VSL of R7 should be High VSL
because RC must be notified if CAP has changed since changes in action or timetables may require the RC to intervene to maintain reliability.
Secondly, HQT suggests to remove footnote 3 on page 23, footnote 5 on page 25, and footnote 6 on page 27 by modifying the Applicability section
4.2.1 in section 4.2 entitled Facilities by the following: ‘‘Remedial Action Schemes (RAS) not designated as “limited impact”. A RAS designated as
“limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations.’’
Thirdly, regarding requirement R8, as mentioned in HQT’s general comments above, as for protection systems, invasive actions (maintenance and
testing activities) may introduce a higher number of misoperations which can stress the electrical system. As recognized in PRC-005, new technology
may offer the benefits to avoid this type of activities. Thus, from a reliability perspective, a RAS Entity should decide which technique is most
appropriate to verify the RAS integrity according to the complexity of their design. If for some reason, a RAS entity would prefer to dynamically extract
and compare the settings file of the RAS components instead of doing functional tests, it could be another acceptable method to meet the intent of
requirement of R8 without doing invasive actions that could adversely affect the reliability of the system.
HQT notes that there is actually no difference made in PRC 005 for limited impact RAS components. However, HQT agrees with PRC 012-2 regarding
the fact that limited impact RAS represents a low reliability risk to the BULK power system. For those RAS, HQT agrees that less stringent criteria can
be applied. In PRC-005, there is no mention of limited impact RAS components, this concept should be incorporated within the standard.
Finally, in light of the above comments, HQT is of the view that the maximum allowable interval between functional tests should be twelve full calendar
years for RAS that are not designated as limited impact RAS.
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Larry Heckert - Larry Heckert
Answer
Yes
Document Name
Comment
Alliant Energy supports comments submitted by the MRO NERC Standards Review Forum.
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Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer
Yes
Document Name
Comment
In the Supplemental Material, on p. 30 of 55 of the redlined document, please clarify what is meant by “…affected by the contingency.” Specifically, is
this the contingency that would require RAS operation, or is the contingency the overloading of the BES Element?
Outside of the scope of the survey question -- in Measurement M5, please consider changing “…with participating RAS-entities and…” to “…with
participating RAS-entities, if applicable, and…”
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David Greene - SERC Reliability Corporation - 10, Group Name SERC DRS
Answer
Document Name
Comment
Yes
SERC DRS suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS considered
to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be experienced by just
one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or unreliable BES, and we do not
believe that this should remove an RAS from limited impact consideration.
The comments expressed herein represent a consensus of the views of the above-named members of the SERC EC Dynamics Review Subcommittee
only and should not be construed as the position of SERC Reliability Corporation, its board, or its officers.
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Answer
Yes
Document Name
Comment
However, the NSRF proposes including the following opinion in the Supplemental Material section:
R4 – This requirement refers to ‘single component malfunction’ and ‘single component failure’. However, the standard does not contain any qualification
of which types of components must be included in RAS evaluations or what entity ultimately makes the component inclusion determination. Therefore,
to avoid making elaborate component inclusion qualifications or letting there be uncertainty over which entity makes the final component inclusion
determination, add text to the Supplemental Material section such as, “The RC will make the final determination regarding which RAS components are
included in the RAS evaluation during its review”.
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William Temple - William Temple
Answer
Yes
Document Name
Comment
PJM supports the comments submitted by the ISO/RTO Council.
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1
Public Service Enterprise Group , 1,3,5,6, Koncz Christy
Response
John Pearson - John Pearson
Answer
Yes
Document Name
Comment
Requirement R4.1.3 includes language from the associated footnote verbatim. The language in the footnote should be deleted. The requirement also
seems to define a limited impact RAS. The NERC Glossary should include the definition of a limited impact RAS.
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Erika Doot - U.S. Bureau of Reclamation - 5
Answer
Yes
Document Name
Comment
The Bureau of Reclamation agrees with the changes proposed by the drafting team.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC No HQ and Dominion
Answer
Document Name
Yes
Comment
Footnote 1 in Requirement R4 is not needed as written. It just reiterates the wording of sub 4.1.3. Same applies to footnote 9 on page 46 as the
wording in sub 4.1.3 pertains to the entire document. An appropriate footnote would read that NPCC Type 3 classification and the WECC LAPS
classifications will be recognized as limited-impact RAS.
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John Fontenot - Bryan Texas Utilities - 1
Answer
Yes
Document Name
Comment
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Michael DeLoach - AEP - 3
Answer
Yes
Document Name
Comment
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Michael DeLoach - AEP - 3
Answer
Yes
Document Name
Comment
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Randi Heise - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion - RCS
Answer
Yes
Document Name
Comment
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC-ISONE
Answer
Yes
Document Name
Comment
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Mike Smith - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
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Thomas Foltz - AEP - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Allie Gavin - Allie Gavin
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed the SDT did not specifically address its comments submitted on January 8, 2016. Texas RE respectfully requests the SDT to
respond to its comments.
As previously stated in comments submitted on January 8, 2016, Texas RE does not agree with the provision that a RAS can be designated as “limited
impact”. Texas RE recommends the SDT reconsider and treat all RASes, that affect the reliability of the Bulk Electric System (BES) equally.
However, if the SDT elects to keep the limited impact designation, Texas RE is concerned the proposed criteria for determining a “limited impact” RAS
is vague and ambiguous (e.g. “… BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations). Absent clear criteria, the RC may designate certain RASes as limited impact that would be more properly characterized as a
RAS. Because limited impact RASes are subject to reduced reliability-related considerations by the Reliability Coordinator (i.e. Attachment 2) and
limited evaluation performed by the Planning Coordinator (i.e. Requirement 4), the improper characterization of RASes may lead to potential reliability
gaps on the BES.
Texas RE inquires as to what the SDT used as technical basis (such as industry reports, recommendations from task forces or working groups, field
studies, etc) in determining to create a requirement to designate limited impact RASes.
TPL-001-4
In Requirement R4.1.5, Texas RE is concerned the planning requirements in TPL-001-4 do not distinguish between limited impact RAS and RAS. For
example under TPL-001-4, a PC must consider an operation of a RAS, including a limited impact RAS, that results in an applicable Facility Rating being
exceeded. Texas RE understands planning and RAS evaluation are separate obligations for the PC with separate requirements. However, the
language in R4.1.5 specifically identifying the “same performance requirements” as defined in TPL-001-4 potentially blurs these two obligations with
respect to limited impact RAS. Texas RE suggests eliminating the phrase “Except for limited impact RAS” in R4.1.5 so PRC-012-2 and TPL-001-4
cannot be interpreted to potentially conflict with each other.
Degraded RAS
Texas RE submitted comments on October 5, 2015 stating its concern there is no requirement to report the degraded RAS to the RC. The SDT
responded:
The status of a degraded RAS is required to be reported (in Real-time) to the Transmission Operator via PRC-001, Requirement R6, then to the RC via
TOP-001-3, Requirement R8. See Phase 2 of Project 2007-06 for the mapping document from PRC-001 to other standards regarding notification of RC
by TOP if a deficiency is found during testing. Consequently, it is not necessary to include a similar requirement in this standard.
Texas RE does not agree this issue is handled in the standards identified by the SDT in its response. As an initial matter, TOP-001-3 R8 does not
necessarily require the TOP to inform the RC. TOP-001-3 R8 is specifically limited to Emergencies, which do not necessarily include degradation of a
RAS. Does the SDT envision treating all RAS degradations as Emergencies as defined by the NERC Glossary of Terms in order to trigger the TOP001-3 R8 reporting obligations?
TOP-001-3 also uses the term “Transmission Operator Area” which, by definition, does not necessarily include DP and GO, which are “RAS-entities”,
equipment if used in a RAS. This is a gap in reliability.
In addition, other related standards do not appear to require RAS-entities to report degraded RASes to the RC in all circumstances. For example, TOP003-3 discusses having a data specification and distributing the data specification. However, this Standard does not explicitly include notification of
actual degradation of a RAS to an RC or explicitly require entities to provide actual data. In particular, TOP-003-3 R3 states “Each Transmission
Operator shall distribute its data specification to entities that have data required by the Transmission Operator’s Operational Planning Analyses, Realtime RAS monitoring, and Real-time Assessment.” Moreover, TOP-003-3 R3 explicitly covers the “Operations Planning” Time Horizon (not Real-time or
Same-Day Operations). TOP-003-3 R5 also states “Each Transmission Operator, Balancing Authority, Generator Owner, Generator Operator, LoadServing Entity, Transmission Owner, and Distribution Provider receiving a data specification in Requirement R3 or R4 shall satisfy the obligations of the
documented specifications…”. Again, under this Standard, there is no explicit requirement that entities provide the RC that is reviewing and approving
the RAS the actual data regarding the “current Protection System and Special Protection System status or degradation that impacts System reliability.”
Misoperations
The definition of Misoperation that becomes effective on July 1, 2016 does not include RASes. Texas RE recommends clarifying R5 by defining
misoperation to align with PRC-004-4. If misoperation is not defined, entities might not do the actions outlined in R 5.1. The SCPS drafted a RAS
template to describe misoperations which were never officially approved. Texas RE recommends adding a definition of misoperations for RASes in the
Standard or NERC Glossary based on the SCPS RAS template and the language in R5.
Also, while reporting of Protection Systems Misoperations will be contained within the Section 1600 Data Request for PRC-004, neither PRC-012-2 nor
the Section 1600 data request provides a corresponding reporting requirement for RAS misoperations to the Regional Entities or NERC. Texas RE
recommends the SDT consider adding a requirement, either to PRC-012-2 or to the Section 1600 data request, for Registered Entities to report
misoperations of RASes to regional entities.
Functional Testing – R8
Texas RE is concerned PRC-012-2 R8 does not address the scenario where a RAS is owned by different companies. In particular, PRC-012-2 R8, as
currently drafted, does not require simultaneous testing each separately-owned component of the RAS-system simultaneously so that entities can verify
that the RAS properly operates. For example, there are instances in Texas where a GO and TO own part of the same RAS. Under the current
Standard language, the GO will test the receipt signal and the TO will test sending signal. However, there is no requirement for the GO and TO to
coordinate the tests of their individual components to ensure that signal is sent and received. Put differently, although each individual component may
be tested, there is no corresponding test of to ensure the entire RAS will operate as intended. Texas RE is concerned a reliability gap will occur if the
two tests are not conducted simultaneously and in such a way the GO and TO can view the results of the test on the entire RAS.
Full Calendar Months
The SDT introduces a new term “full calendar months” that is neither defined in the Standard nor the NERC Glossary and is inconsistent with other
Reliability Standards. Texas RE noticed a definition in the PRC-012-2 RSAW, but the definition should be in the NERC Glossary or within PRC-012-2
itself instead. Texas RE recommends the SDT provide the definition within the Standards process while considering other definitions already in place
(such as “Calendar Year” in PRC-005-6).
Corrective Action Plan
As previously submitted on January 8, 2015, Texas RE recommends revising PRC-12-2 R7 to place at least minimal criteria around modifications to
Corrective Action Plans (CAP) or corresponding CAP timetables. As currently drafted, PRC-12-2 R7 could be interpreted to permit RAS-entities to
perpetually update their CAPs if “actions or timetables change” and then merely notify the RC of such changes. Texas RE recommends that the SDT
consider some minimal criteria that RAS-entities must satisfy in order to update a CAP under PRC-12-2 R7.2. For instance, PRC-12-2 R7.2 could be
revised to read: “Update the CAP for any reasonable changes in the required actions or implementation timetable.” In turn, PRC-12-2 R7.3 could be
revised to read: “Notify each reviewing Reliability Coordinator and provide a reasoned justification for changes in CAP actions or timetables, and notify
each reviewing Reliability Coordinator when the CAP is completed.”
Feedback Mechanism
Texas RE noticed there is no feedback mechanism in the current standard for PCs to incorporate RC approved RAS modifications in subsequent
planning processes. Texas RE understands this might not appropriate for the scope of this project, but requests the SDT to consider this issue in future
reviews of applicable standards.
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0
2. Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to provide for the initial consideration of limited
impact RAS, and to clarify that the initial obligation under Requirement R9 for a Reliability Coordinator that does not have a RAS database is
to establish a RAS database by the effective date of PRC-012-2. Do you agree with the revised Implementation Plan? If no, please provide the
basis for your disagreement and an alternate proposal.
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
No
Document Name
RS--3-15-16--2010-05 3_PRC-012-2_Unofficial_Comment_Form_2016-03-18- Final.docx
Comment
In light of the above comments, HQT is of the view that the maximum allowable interval between functional tests should be twelve full calendar years for
RAS that are not designated as limited impact RAS.
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0
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Douglas Webb - Douglas Webb
Answer
No
Document Name
Comment
In consideration of our comments relating to the term “limited impact,” we are unable to support the Implementation Plan. The alternative proposal is
incorporate into the Implementation Plan a future defined NERC Glossary term for “limited impact.”
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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Document Name
Comment
ERCOT signs on to the IRC SRC comments for Question 2. The SRC comments are as follows:
• The rationale for R2 states that RC review “minimizes the possibility of a conflict of interest that could exist because of business relationships
among ….” This explanatory purpose for R2 is not needed and in fact could prove untrue as not all RCs are independent from TOs, GOs, etc.
• The R3 rationale inserts the idea of “lack of dependability”. This can be understood differently by different parties. For a hardware supplier, it
can mean the equipment or technology is unreliable. And if taken to an extreme, this seems to open the path to requiring the RC to decide which
generators should run based on the individual generators’ forced outage rate (dependability rate?). We suggest this phrase be stricken from the R3
explanatory.
• For R4 the limited impact designation explanation, please clarify whether the reference to regions is meant to be an example of how the SDT
came to its decision for R4 or whether it is a reference of the authority of what regions can do. We believe it is the former and the language should be
improved.
• The concept of 4.1.2 to “avoid adverse interactions” would seem to need some criteria for evaluating what “avoid” means. Rather than state
“avoid”, we suggest this requirement to be rewritten to state: “The RAS does not adversely impact the performance of other RAS, and protection and
control systems.”
·
4.1.4.4. BES voltages shall be within post
‐Contingency
tablished by the
voltag e lim
Transmission Planner and the Planning Coordinator. Some Planners don’t use voltage deviation criteria. This should it not be rewritten to state “BES
voltages shall be within the Planning Coordinator’s voltage criteria under pre and post contingency conditions”.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
No
Document Name
Comment
Implementation Plan
Texas RE recommends reducing the implementation period. This is a series of processes that already exist in some form or fashion and should not
require a new construct that would take three years. In Requirement R9, the SDT indicates requirements follow “industry practice” which is a twelve
month periodicity. Does the SDT contend that there are RASes in place that an RC or PC does not know about?
Texas RE recommends that the SDT eliminate the proposed implementation period or at least shorten the proposed three-year implementation period
for PRC-12-2 to six months. Alternatively, the SDT should link the 60-full-calendar month (currently revised to “5 full calendar years”) compliance
window in PRC-12-2, R4 and the six- and twelve-year compliance periods in PRC-12-2, R8 to the effective date of PRC-12-2 and not the extended date
(if any) set forth in the proposed implementation plan.
The proposed PRC-12-2 establishes a process for reviewing new, functionally modified, or retiring RAS. As the SDT has recognized, failing to
implement such a RAS review process could result in a significant gap in reliability. Specifically, the SDT stated in the rationale for Requirement R1 that
RAS “action(s) can have a significant impact on the reliability and integrity of the Bulk Electric System (BES).” Given the importance of the RAS review
scheme for reliability, Texas RE believes that three years is too long to implement the process contemplated in the proposed PRC-12-2.
Review Process Timeline
Texas RE also believes that the nature of the review process itself also counsels in favor of a shorter review period. For example, PRC-12-2, R1 – R3
establishes the basic framework for RAS review. These requirements mandate that RAS-entities provide certain information regarding RAS to their
respective Reliability Coordinators (RC), a minimum four full calendar month period for the RC to review this information, and then a subsequent
obligation for the RAS-entity to resolve any reliability issues identified by the RC prior to installing, functionally modifying, or retiring a particular
RAS. Accordingly, these requirements do not contemplate immediate changes to existing physical assets, significant internal process transformations,
or other issues that could potentially justify a three-year implementation period. Rather, they largely focus solely on the exchange and review of
documentation, such as one-line drawings, for each RAS that is likely already be in the RAS-entity’s possession today. RAS-entities and their
associated RCs should therefore be able to begin the RAS review process with only minimal lead time following the adoption of PRC-12-2. Texas RE
would further note that although RCs may need additional compliance resources to perform the RAS reviews contemplated under PRC-12-2, the
existing language in PRC-12-2, R2 already provides RCs and RAS-entities with the flexibility to extend the review period if necessary based on a
“mutually agreed upon schedule.”
A similar rationale applies to the misoperation review and correction process in PRC-12-2, R5. As the SDT notes, “[t]he correct operation of a RAS is
important for maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS indicates that the RAS effectiveness and/or
coordination has been compromised.” Texas RE agrees with this statement. In light of this fact, however, Texas RE believes that RAS-entities should
begin RAS operational performance assessments following a RAS failure or misoperation immediately upon adoption of PRC-12-2 in order to avoid a
significant reliability gap.
If the SDT elects to retain an implementation period of any length, Texas RE recommends that such implementation plan not apply to PRC-12-2, R4
and R8. These requirements already have significant time periods for RAS-entities to complete their compliance obligations embedded within
them. For example, RAS-entities have six years under PRC-12-2, R8 to complete initial functional tests of their RAS (and 12 years for limited impact
RAS if that definition is retained). Given that PRC-12-2, R4 and R8 already provide extended compliance horizons, Texas RE does not believe that
additional time is necessary to implement these requirements. Instead, the 6-full-calendar month period in PRC-12-2, R4 and the six- and twelve-year
periods in PRC-12-2, R8 should begin on the effective date of PRC-12-2 itself.
Additionally, the Implementation Plan contains the same “limited impact” language Texas RE has concerns about.
Texas RE requests the SDT provide justification for the testing timelines.
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Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
There was no general comment section provided this round, so TVA is providing the following comments to support our negative votes on the ballot:
TVA continues to believe that the responsibility for reviewing and approving new or functionally modified RAS schemes belongs with the Planning
Coordinator and not the Reliability Coordinator. Oversight of the planning of the Bulk Electric System or the entities responsible for Bulk Electric System
planning belongs with the Planning Coordinator. From TVA’s perspective, the proposed standard, as written, is in direct conflict with the Functional
Model, and requires a compelling reason to justify the deviation. The facts that there are fewer Reliability Coordinators (as opposed to Planning
Coordinators) and that the Reliability Coordinators have the “widest-area view” do not support a significant deviation from the Functional
Model. Moreover, such analysis would beyond the normal Reliability Coordinator functions, the Reliability Coordinators would not have the expertise to
conduct RAS analysis in the planning horizon. Simply put, Reliability Coordinators do not have trained personnel or the appropriate tools to complete a
comprehensive assessment. Planning Coordinators have oversight over all other aspects of planning of the Bulk Electric System, and there is no
reason to treat Remedial Action Schemes differently.
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Ben Engelby - ACES Power Marketing - 6, Group Name ACES Standards Collaborators - PRC-012-2 Project
Answer
Yes
Document Name
Comment
We agree with the SDT that the implementation plan is appropriate.
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0
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0
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William Temple - William Temple
Answer
Yes
Document Name
Comment
PJM supports the comments submitted by the ISO/RTO Council.
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0
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0
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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC-ISONE
Answer
Document Name
Yes
Comment
The rationale for R2 states that RC review “minimizes the possibility of a conflict of interest that could exist because of business relationships among
….”. This explanatory purpose for R2 is not needed and in fact could prove untrue as not all RCs are independent from TOs, GOs, etc.
The R3 rationale inserts the idea of “lack of dependability”. This can be understood differently by different parties. For a hardware supplier, it can mean
the equipment or technology is unreliable. And if taken to an extreme, this seems to open the path to requiring the RC to decide which generators
should run based on the individual generators’ forced outage rate (dependability rate?). We suggest this phrase be stricken from the R3 explanatory.
For R4 the limited impact designation explanation, please clarify whether the reference to regions is meant to be an example of how the SDT came to
its decision for R4 or whether it is a reference of the authority of what regions can do. We believe it is the former and the language should be improved.
The concept of 4.1.2 to “avoid adverse interactions” would seem to need some criteria for evaluating what “avoid” means. Rather than state “avoid”, we
suggest this requirement to be rewritten to state: “The RAS does not adversely impact the performance of other RAS, and protection and control
systems.”
4.1.4.4. BES voltages shall be within post
ished
‐Conting
by ency
the voltag e lim it
Transmission Planner and the Planning Coordinator. Some Planners don’t use voltage deviation criteria. This should it not be rewritten to state “BES
voltages shall be within the Planning Coordinator’s voltage criteria under pre and post contingency conditions”.
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Larry Heckert - Larry Heckert
Answer
Yes
Document Name
Comment
Alliant Energy supports comments submitted by the MRO NERC Standards Review Forum.
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0
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0
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC No HQ and Dominion
Answer
Yes
Document Name
Comment
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0
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0
Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Oshani Pathirane - Oshani Pathirane
Answer
Yes
Document Name
Comment
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0
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0
Response
Andrew Pusztai - American Transmission Company, LLC - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
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0
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0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
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0
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
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0
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0
Response
Jared Shakespeare - Peak Reliability - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Erika Doot - U.S. Bureau of Reclamation - 5
Answer
Document Name
Yes
Comment
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0
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0
Response
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Allie Gavin - Allie Gavin
Answer
Yes
Document Name
Comment
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0
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0
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John Pearson - John Pearson
Answer
Yes
Document Name
Comment
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0
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0
Teresa Czyz - Oglethorpe Power Corporation - 5
Answer
Yes
Document Name
Comment
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0
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0
Response
Greg Davis - Greg Davis
Answer
Yes
Document Name
Comment
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0
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0
Response
Christy Koncz - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG
Answer
Yes
Document Name
Comment
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0
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0
Response
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
Yes
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0
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0
Response
Mike Smith - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Yes
Document Name
Comment
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0
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0
Response
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Answer
Yes
Document Name
Comment
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0
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Response
0
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Randi Heise - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion - RCS
Answer
Yes
Document Name
Comment
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0
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0
Response
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer
Yes
Document Name
Comment
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0
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0
Response
Gul Khan - Gul Khan
Answer
Document Name
Comment
Yes
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0
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0
Response
Michael DeLoach - AEP - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
Michael DeLoach - AEP - 3
Answer
Yes
Document Name
Comment
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0
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0
Response
John Fontenot - Bryan Texas Utilities - 1
Answer
Yes
Document Name
Comment
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Daniel Mason - City and County of San Francisco - 5
Answer
Yes
Document Name
Comment
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Additional Comments:
PSEG
Requirement 1 – There are no clear lines of responsibility for jointly owned RASs.
The concept of a RAS-entity causes RAS-entity causes confusion for entities that have joint ownership of a RAS. While the SDT recognizes this issue
by stating: “ Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would collaborate and submit a single, coordinated
Attachment 1to the reviewing RC”. While PSEG agrees with the intent of this statement, it is included in the “Rationale” section of the draft
standard and therefore that language will not be incorporated into the final standard. Furthermore, PSEG believes that PSEG that the language of
R1 would still require each RAS entity to submit all information in Attachment 1to the Reliability Coordinator, which is inconsistent with the
Paragraph 81 effort and the Reliability Assurance Initiative. PSEG believes such intent could be incorporated in to R1 as follows:
R1. Prior to placing a new or functionally modified RAS in‐service or retiring an existing RAS, each the RAS‐entity shall provide the information
identified in Attachment 1 for review to the Reliability Coordinator(s) where the RAS is located. If there are multiple RAS-entities, the entities may
delegate a single mutually agreeable RAS-entity to submit Attachment 1 on their behalf.
PSEG wishes to note that such language would not be useful in situations where the one or more of the RAS-entities that jointly own a RAS do not
want to cooperate or cannot agree upon a single lead entity. Additionally, PSEG believes that a single entity (either the Reliability Coordinator or
the Planning Coordinator) should be responsible for coordinating the RAS entities.
Attachment 1 – Attachment 1 should have defined roles for the Planning Coordinator (PC) or Transmission Planner (TP).
Since the requirement for new and revised remedial action schemes are likely to be initiated by the results of Transmission system planning
performance assessments done by the TP or PC in compliance with TPL-001-4, one of those entities would be best suited to perform many of the
activities listed under section II of Attachment 1.
Furthermore, the technical studies that are required by Attachment 1 should not be performed individually by each RAS-entity because they do
not have the skills or tools available to perform such analyses. For example, if an independent generator is asked by its RC to implement a run-back
scheme to resolve a stability issue, it is unlikely that that entity would have to tools available to provide the information required under
Attachment 1, item II.6.
Rather, PSEG recommends that the RAS-entities’ PC or (TP) conduct the assessment of the System performance of a proposed new, modified, or
retired RAS. Under this construct a RAS-entity implementing a new, modified, or retired RAS would submit an application under R1 containing
general information as well as details concerning the proposed components and logic of the RAS to its TP or PC and to other RAS-entities that
would participate in the RAS The PC or TP in turn would conduct the assessment of the proposed RAS to determine if the proposed RAS resolves
the System performance issues, and forward that information to the RC for consideration under Requirement 2.
Seattle City Light
Project 2010-05.3 PRC-012-2 RAS Seattle City Light Comments Additional Ballot and Non-Binding Poll March 16, 2016
SCL COMMENTS
Clarification of Roles and Responsibilities for RAS Equipment Ownership by Multiple Entities:
4.1.3 RAS‐entity
The RAS‐entity is any Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. If all of the RAS (RAS
components) have a single owner, then that RAS entity has sole responsibility for all the activities assigned within the standard to the RAS‐entity. If
the RAS (RAS components) have more than one owner, then each separate RAS component owner is a RAS‐entity and is obligated to participate in
various activities identified by the Requirements.
The standard does not stipulate particular compliance methods. RAS‐entities have the option of collaborating to fulfill their responsibilities for each
applicable requirement. Such collaboration and coordination may promote efficiency in achieving the reliability objectives of the requirements;
however, the individual RAS‐entity must be able to demonstrate its participation for compliance. As an example, the individual RAS‐entities could
collaborate to produce and submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to initiate the RAS review
process.
Per 4.1.3 RAS-entity discussion, City Light does not agree with the current definition from within the standard or the way responsibility is assigned.
Compliance responsibility is being assigned to entities that cannot, by themselves, perform required actions to achieve compliance. Instead,
entities that participate in a RAS scheme must rely on the original or current designer and owner of the scheme to perform work and perform
coordination efforts. Without assigning primary and secondary (minor) RAS-entity responsibilities, issues could arise that are beyond the control of
obligated entities. For an entity that only has end of the line equipment involved in the scheme, such as breaker trip coils, too much obligation falls
on this entity that has a minor role. A large number of entities will fall into the category of owning a very small supporting portion of a RAS scheme
and who do not have the means (information they do not control or determine) to perform the required reporting. Differentiation should be made
between the primary RAS-entity (owner of a RAS scheme, primary) and owners of pieces of equipment who play a minor role for the primary RAS
scheme. The standard should be rewritten to differentiate between primary and secondary (minor) to clarify roles and responsibilities.
As was mentioned in previous draft comments by others, this standard works great when there is one entity that owns the entire scheme. R3, R5,
R6, R7, and R8 should be revised to designate overall responsibility to an owner of the scheme, with all secondary (minor participants) involved in
the scheme being required to support the owner of the scheme in their development and reporting obligations. The primary RAS-entity that
designs, owns and controls the RAS should be the one responsible for coordinating and meeting these requirements from the standard.
Other possible implications:
City Light additionally suggests that the term RAS-entity only apply to this standard and not be placed in the Glossary of Terms. If City Light is
labeled as a RAS-entity under this current drafted definition, we would be defined as owning some or all of a RAS. There are no approved
definitions for a RAS Owner. Project 2010-05.3 PRC-012-2 RAS Seattle City Light Comments Additional Ballot and Non-Binding Poll March 16, 2016
Other standards that assign RAS responsibilities do so under the applicability verbiage of “XXXX that owns an SPS”. City Light feels this would
impose undue confusion and compliance responsibility on entities that are minimally involved in a RAS. Therefore, RAS Entity should be only
applicable to this standard.
We suggest adding the below defined term and language which would help serve three purposes. First to clarify who has responsibility for certain
aspects of this standard. Secondly, to help clarify which entity has responsibility under current and future enforced RAS related standards such as
PRC-017-1. Lastly, the proposed term would align with current WECC assignments of RAS responsibility.
RAS-owner—the Transmission Owner, Generator Owner, or Distribution Provider that is the majority owner and operator of a RAS, this is
normally identified using the following prioritization;
The RAS-owner is the Transmission Owner of the scheme. Where there is not a Transmission Owner that owns a portion of the RAS, the
Generator Owner becomes the RAS-owner. Where there is not a Transmission Owner or a Generator Owner that owns a portion of the RAS,
the Distribution Provider becomes the RAS-owner.
In conclusion, revising the standard to clarify roles and responsibilities between the primary and secondary (participants) is crucial to the successful
implementation of this standard when RAS components are owned by multiple entities.
Thanks you for your time and efforts in developing a successful standard
Consideration of Comments
Project Name: 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS) | PRC-012-2
Comment Period Start Date: 2/3/2016
Comment Period End Date: 3/18/2016
Associated Ballots: 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes PRC-012-2 AB 3 ST, 2010-05.3 Phase 3 of
Protection Systems: Remedial Action Schemes PRC-012-2 Non-binding Poll AB 3 NB
There were 43 responses, including comments from approximately 131 different people from approximately 84 different companies
representing 8 of the 10 Industry Segments as shown on the following pages.
All comments submitted can be reviewed in their original format on the project page.
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 Director of Standards, Howard
Gugel (via email) or at (404) 446‐9693.
The drafting team made grammatical edits and footer updates to all documents and provided additional information in the Rationale
boxes and Supplemental Material section of the draft standard based on stakeholder comments.
Questions
1. PRC-012-2: Requirements R4 and R6, Attachments 1 and 2, and the Supplemental Material section of the standard were modified for clarity
and completeness. Do you agree with the proposed changes? If no, please provide the basis for your disagreement and an alternate
proposal.
2. Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to provide for the initial consideration of limited
impact RAS, and to clarify that the initial obligation under Requirement R9 for a Reliability Coordinator that does not have a RAS database is
to establish a RAS database by the effective date of PRC-012-2. Do you agree with the revised Implementation Plan? If no, please provide
the basis for your disagreement and an alternate proposal.
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
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
2
Organization
Name
Name
ACES Power Ben Engelby
Marketing
Segment(s)
6
Region
Group Name Group Member
Name
ACES
Ellen Watkins
Standards
Collaborators
- PRC-012-2 Shari Heino
Project
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
Sunflower
1
Electric Power
Corporation
SPP RE
Brazos Electric 1,5
Power
Cooperative,
Inc.
Texas RE
Ginger Mercier
Prairie Power, 1,3
Inc.
SERC
Mark
Ringhausen
Old Dominion 3,4
Electric
Cooperative
RF
Caitlin Schiebel
Buckeye
Power, Inc.
RF
John Shaver
Arizona
1,4,5
Electric Power
Cooperative,
Inc. Southwest
Transmission
Cooperative,
Inc. and
Southwest
Transmission
Cooperative,
Inc.
4
WECC
3
Southwest
Charles Yeung 2
Power Pool,
Inc. (RTO)
Public
Service
Enterprise
Group
Christy Koncz 1,3,5,6
SPP RE
NPCC,RF
SRC-ISONE
PSEG
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
Bill Hutchison
Southern
1
Illinois Power
Cooperative
SERC
Scott Brame
North Carolina 3,4,5
Electric
Membership
Corporation
SERC
Chip Koloini
Golden Spread 5
Electric
Cooperative
SPP RE
Bill Hutchison
Southern
1
Illinois Power
Cooperative
SERC
Charles Yeung
SPP
2
SPP RE
Ben Li
IESO
2
NPCC
Ali Miremadi
CAISO
2
WECC
Greg Campoli
NYISO
2
NPCC
Liz Axson
ERCOT
2
Texas RE
Lori Spence
MISO
2
MRO
Mark Holman
PJM
2
RF
Tim Kucey
PSEG - PSEG
Fossil LLC
5
RF
Karla Jara
PSEG - Energy 6
Resources and
Trade LLC
RF
Joseph Smith
PSEG - Public
Service
RF
1
4
Electric and
Gas Co.
Jeffrey Mueller
Duke Energy Colby Bellville 1,3,5,6
SERC
David Greene 10
Reliability
Corporation
MRO
Emily
Rousseau
1,2,3,4,5,6
PSEG - Public
Service
Electric and
Gas Co
3
RF
Duke Energy
1
RF
Lee Schuster
Duke Energy
3
FRCC
Dale Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Mei Li
Entergy
1
SERC
Zakia El Omari
GTC
1
SERC
Wade Richards
SCPSA
1
SERC
Bob Jones
Southern
Company
Services
1
SERC
John O'Connor
DEP
1
SERC
John Sullivan
Ameren
1
SERC
Tom Cain
TVA
1
SERC
Venkat Kolluri
Entergy
1
SERC
Joe Depoorter
Madison Gas
& Electric
3,4,5,6
MRO
1
MRO
FRCC,RF,SERC Duke Energy Doug Hils
SERC
MRO
SERC DRS
MRO-NERC
Standards
Review
Forum
(NSRF)
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
Chuck Lawrence American
Transmission
Company
5
Chuck Wicklund Otter Tail
Power
Company
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
1,3,5
MRO
Dave Rudolph
Basin Electric 1,3,5,6
Power
Cooperative
MRO
Kayleigh
Wilkerson
Lincoln
Electric
System
MRO
Jodi Jenson
Western Area 1,6
Power
Administration
MRO
Larry Heckert
Alliant Energy 4
MRO
Mahmood Safi
Omaha Public 1,3,5,6
Utility District
MRO
1,3,5,6
Shannon Weaver Midwest ISO
Inc.
2
MRO
Mike Brytowski
Great River
Energy
1,3,5,6
MRO
Brad Perrett
Minnesota
Power
1,5
MRO
Scott Nickels
Rochester
4
Public Utilities
MRO
Terry Harbour
MidAmerican 1,3,5,6
Energy
Company
MRO
6
Tom Breene
3,4,5,6
MRO
Tony Eddleman Nebraska
1,3,5
MRO
Amy Casucelli
Xcel Energy
1,3,5,6
MRO
Pawel Krupa
Seattle City
Light
1
WECC
Dana Wheelock Seattle City
Light
3
WECC
Hao Li
Seattle City
Light
4
WECC
Bud (Charles)
Freeman
Seattle City
Light
6
WECC
Mike haynes
Seattle City
Light
5
WECC
Michael Watkins Seattle City
Light
1,3,4
WECC
Faz Kasraie
Seattle City
Light
5
WECC
John Clark
Seattle City
Light
6
WECC
Robert A.
Schaffeld
Southern
Company
Services, Inc.
1
SERC
Wisconsin
Public Service
Corporation
Public Power
District
Seattle City
Light
Southern
Company Southern
Ginette
Lacasse
Pamela
Hunter
1,3,4,5,6
1,3,5,6
WECC
SERC
Seattle City
Light Ballot
Body
Southern
Company
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
7
Company
Services, Inc.
Dominion Dominion
Resources,
Inc.
R. Scott Moore
Randi Heise
Northeast
Ruida Shu
Power
Coordinating
Council
5
1,2,3,4,5,6,7 NPCC
Dominion RCS
RSC No HQ
and
Dominion
Alabama
Power
Company
3
SERC
William D. Shultz Southern
Company
Generation
5
SERC
John J. Ciza
Southern
Company
Generation
and Energy
Marketing
6
SERC
Larry Nash
Dominion
1
Virginia Power
SERC
Louis Slade
Dominion
Resources,
Inc.
6
SERC
Connie Lowe
Dominion
Resources,
Inc.
3
RF
Randi Heise
Dominion
Resources,
Inc.
5
NPCC
Paul Malozewski Hydro One
1
NPCC
Guy Zito
NA - Not
Applicable
NPCC
Northeast
Power
Coordinating
Council
Brian Shanahan National Grid 1
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
NPCC
8
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
Rob Vance
New
Brunswick
Power
1
NPCC
Mark J. Kenny
Eversource
Energy
1
NPCC
Gregory A.
Campoli
NY-ISO
2
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Wayne Sipperly New York
Power
Authority
4
NPCC
David
Ramkalawan
Ontario Power 4
Generation
NPCC
Glen Smith
Entergy
Services
4
NPCC
Brian O'Boyle
Con Edison
5
NPCC
Brian Robinson
Utility Services 5
NPCC
Bruce Metruck
New York
Power
Authority
6
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
Michael Jones
National Grid 3
NPCC
9
Southwest
Shannon
Power Pool, Mickens
Inc. (RTO)
2
SPP RE
SPP
Standards
Review
Group
Michael Forte
Con Edison
1
NPCC
Kelly Silver
Con Edison
3
NPCC
Brian O'Boyle
Con Edison
5
NPCC
Edward Bedder
Orange &
Rockland
Utilities
1
NPCC
David Burke
UI
3
NPCC
Peter Yost
Con Edison
4
NPCC
Helen Lainis
IESO
2
NPCC
Michele Tondalo UI
1
NPCC
Kathleen
Goodman
ISO-NE
2
NPCC
Silvia Parada
Mitchell
NextEra
Energy, LLC
4
NPCC
Shannon
Mickens
Southwest
Power Pool
Inc.
2
SPP RE
Jason Smith
Southwest
Power Pool
Inc.
2
SPP RE
Patrick McPhail
Grand River
1
Dam Authority
SPP RE
Robert Hirchak
Cleco
1,3,5,6
SPP RE
1,3,5
MRO
Jamison Cawley Nebraska
Power Public
District
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
10
Greg Hill
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
Nebraska
Power Public
District
1,3,5
MRO
11
1. PRC-012-2: Requirements R4 and R6, Attachments 1 and 2, and the Supplemental Material section of the standard were modified for
clarity and completeness. Do you agree with the proposed changes? If no, please provide the basis for your disagreement and an
alternate proposal.
Barbara Kedrowski - WEC Energy Group, Inc. - 3,4,5,6 - RF
Answer
No
Comment
We object to Generator Owners having a primary role in this standard. The nature of a RAS is not to protect individual generators, for
these must have adequate protection for faults or abnormal operating situations. The RAS is typically designed to maintain the reliability
of a significant area of the overall power system. As such, the Transmission Owner is the best entity to ensure that RAS are employed
correctly. Unlike the GO, the TO has the “wide-area” scope of monitoring and system responsibility.
The draft standard is deficient due to the patchwork nature of responsibility for a RAS, especially when there are multiple Owners of
portions of the RAS. There needs to be a single RAS Owner that has overall responsibility for ensuring the requirements of PRC‐012‐2 are
met. This RAS Owner should be a Transmission Owner, not a Generator Owner. The TO (RAS Owner) should take the lead in developing
the data needed for requirements R1 and R3, with the other RAS entities being required to provide data and equipment modifications as
needed. Requirements R5 through R8 should apply to the RAS-Owner, not the RAS entities. The RAS Owner should be the point of
contact with the Planning Coordinator/Reliability Coordinator, with the RAS entities having responsibility to collaborate with the RAS
Owner as needed.
Likes
1
Dislikes
U.S. Bureau of Reclamation, 5, Doot Erika
0
Response
Thank you for your comments.
The drafting team is charged with assigning the requirements of PRC-012-2 to the specific users, owners, and operators of the Bulk‐Power
System while incorporating the reliability objectives of all the RAS‐related standards. The term RAS‐entity is defined in the Applicability as
the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. For purposes of PRC-012-2, a
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
12
Generator Owner (RAS-entity) that owns RAS components is responsible to participate in the various activities identified by the
requirements to the extent of its ownership. RAS-entities have the option of collaborating to fulfill their responsibilities for each
applicable requirement; however, the individual RAS-entity must be able to demonstrate its participation for compliance.
Daniel Mason - City and County of San Francisco - 5
Answer
No
Comment
The Standards identifies a RAS-entity as "the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a
RAS". In some cases this "part" could be as limited as a sensing device providing input to another entity's RAS logic and interupting
devices. For those RAS-entities that find themselves in that situation, providing the information identified in Attachments 1 and 2 is not
appropriate. The Standard should clear up reporting responsibilities for such minor RAS-entities, perhaps by employ the concept of a
"RAS Reporting Agent" for each RAS.
Likes
0
Dislikes
0
Response
Thank you for your comments.
For purposes of PRC-012-2, the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS is a RASentity as defined in the Applicability. The RAS-entity is responsible to participate in the various activities identified by the requirements to
the extent of its ownership. RAS-entities have the option of collaborating to fulfill their responsibilities for each applicable requirement;
however, the individual RAS-entity must be able to demonstrate its participation for compliance.
Gul Khan on Behalf of Rod Kinard, Oncor Electric Delivery - 1
Answer
No
Comment
Oncor does not currently provide the documents mentioned on page 21 of the PRC-012-2 draft 3 standard bullet # 1. We can provide a
simple map of where a RAS will be located but if we are being requested to provide relay functional drawings or detailed 3 line
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
13
schematics we won’t have those drawings developed until the RAS is approved. Additionally even if we have the documents and do send
it to ERCOT, we have a confidentiality concern as these files will get posted in a public information database. We have touched base with
our RC, ERCOT, and they agree that the process we are doing today is satisfactory and is working. Hence we do not see a need to provide
the documentation in attachment 1. The additional information should be optional.
Likes
0
Dislikes
0
Response
Thank you for your comments.
To facilitate a review that promotes reliability, the RAS-entity must provide the RC sufficient details (identified in Attachment 1) of the
RAS design, function, and operation. The information described in Appendix 1 (while not identical) is similar to the information required
by most Regional Entities as part of existing RAS review and approval processes. As stated in Attachment 1, if an item on this list does not
apply to a specific RAS, a response of “Not Applicable” for that item is appropriate. The level of detailed information required is
ultimately at the discretion of the RC. The RC may request additional information on any aspect of the RAS as well as any reliability issue
related to the RAS. If Oncor and ERCOT (the reviewing RC) agree that the documentation provided for RAS review is Critical Infrastructure
Information (CII), all entities involved should handle the information in accordance with all applicable CII guidelines. PRC-012-2 does not
require that the RAS documentation or review be public.
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Answer
No
Comment
SRP appreciates the efforts of the SDT and recommends the removal of the language in the attachments that refers to a “checklist”. Initial
drafts of the attachments were checklists. What is presented cannot be described as a “checklist”. SRP believes this language will create
confusion.
SRP further recommends removing the definition for “limited impact” from the footer of the attachment. If this is to be a definition, it
should be defined in the NERC Glossary of Terms.
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
14
SRP recommends the removal of the definition for “Functionally Modified” from the footer of the documents. Capitalized terms are to be
part of the NERC Glossary of Terms and should not be located outside of that body of work.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The drafting team regards Attachments 1 and 2 as checklists and maintains they should be used as such by the RAS-entity (Attachment 1)
and Reliability Coordinator (Attachment 2).
The Reliability Coordinator has responsibility for the reliability of BES operations within its Reliability Coordinator Area and consequently
has the responsibility to review and approve each RAS before it is implemented in its RC Area. Furthermore, the RC has the discretion to
designate a RAS as limited impact, if applicable, on a case-by-case basis. The drafting team maintains that the general description and
explanatory language regarding the limited impact designation does not rise to the level of a definition that should be included in the
Glossary of Terms Used in NERC Reliability Standards; instead, it provides high-level guidance for the RC to consider during the RAS
review.
The term “functionally modified,” which is incorporated into the standard by reference to Attachment 1, is only intended to provide
guidance to responsible entities for complying with PRC-012-2. The footnote contains examples of what would be considered
“functionally modified.” The drafting team maintains that this guidance does not rise to the level of a definition that should be included in
the Glossary of Terms Used in NERC Reliability Standards, and the footnote is a workable location for this information. The capitalization
of the word “modified” in footnotes 2, 4, and 8 was an error and was corrected. Thank you for pointing this out.
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Answer
No
Comment
AZPS appreciates the efforts of the Standard Drafting Team (SDT) to date and makes the following comments:
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
15
The materials state that a limited impact RAS is “determined by the RC”. AZPS suggests modifying the language to “…limited impact RAS
as determined by the RC based on predefined regionally appropriate criteria.” An RC's determination of whether a RAS is limited impact
should include an evaluation of the potential impacts of the RAS and should reference pre-defined regionally appropriate criteria defined
through a regionally accepted process (e.g. via the RASRC in WECC).
The Technical Justification section directed to Limited Impact states, “The reviewing RC is the sole arbiter for determining whether a RAS
qualifies for the limited impact designation.” While not in direct conflict, AZPS believes that some entities may misinterpret the modified
language as limiting the “The RC from requesting assistance in RAS reviews from other parties such as the PC(s) or regional technical
groups (e.g., Regional Entities)” as provided for earlier in the document. AZPS requests that the “sole arbiter” sentence be clarified to
address this concern.
R4.1.3 is currently amended to state “for limited impact RAS, the inadvertent operation of the RAS or the failure of the RAS to operate
does not cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.” The word “contribute” should be removed because it reduces clarity to the standard. The term
“contribute” is too broad and creates challenges to precisely evaluate.
AZPS appreciates the DT addressing the concern of cases where a RAS crosses one or more RC Area boundaries, each affected RC is
responsible for conducting either individual reviews or participating in a coordinated review by adding language in the appropriate
rational and Supplemental Material sections. AZPS requests the SDT consider if this information would be more impactful as a footnote
to the requirements themselves.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The drafting team maintains that the RC is the functional entity best suited to perform the RAS reviews because it has the widest area
reliability perspective of all functional entities and an awareness of reliability issues in neighboring RC Areas. This Wide Area purview
facilitates the evaluation of interactions among separate RAS as well as interactions among the RAS and other protection and control
systems. The RC has the most comprehensive operational knowledge of the BES in its RC Area. The drafting team declines to make the
suggested change of adding “based on predefined regionally appropriate criteria” as it is not necessary.
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
16
The RC may request and consider input from various parties on any decision. The fact that the RC is responsible for making the final
decision; i.e., is the “sole arbiter,” does not preclude nor conflict with the RC’s ability to request assistance or input; however, the drafting
team made a clarifying revision to the wording in the Supplemental Material section for “limited impact”.
Regarding the use of the term “contribute”, the drafting team contends its inclusion is necessary. Usually, if not always, there is more
than one cause or contributing factor for an event on the BES; whereby, the removal of any one of the individual contributing factors
might have prevented or lessened the severity of the event. The drafting team declines to make the suggested change.
The drafting team sees no benefit in putting the existing language in a footnote and declines to make the suggested change.
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
No
Comment
Need to clarify roles and responsibilities for those RAS that are multi-jurisdictional. See Attached comments
Clarification of Roles and Responsibilities for RAS Equipment Ownership by Multiple Entities:
4.1.3 RAS‐entity
The RAS‐entity is any Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS. If all of the RAS (RAS
components) have a single owner, then that RAS entity has sole responsibility for all the activities assigned within the standard to the
RAS‐entity. If the RAS (RAS components) have more than one owner, then each separate RAS component owner is a RAS‐entity and is
obligated to participate in various activities identified by the Requirements.
The standard does not stipulate particular compliance methods. RAS‐entities have the option of collaborating to fulfill their
responsibilities for each applicable requirement. Such collaboration and coordination may promote efficiency in achieving the reliability
objectives of the requirements; however, the individual RAS‐entity must be able to demonstrate its participation for compliance. As an
example, the individual RAS‐entities could collaborate to produce and submit a single, coordinated Attachment 1 to the reviewing RC
pursuant to Requirement R1 to initiate the RAS review process.
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
17
Per 4.1.3 RAS-entity discussion, City Light does not agree with the current definition from within the standard or the way responsibility is
assigned. Compliance responsibility is being assigned to entities that cannot, by themselves, perform required actions to achieve
compliance. Instead, entities that participate in a RAS scheme must rely on the original or current designer and owner of the scheme to
perform work and perform coordination efforts. Without assigning primary and secondary (minor) RAS-entity responsibilities, issues
could arise that are beyond the control of obligated entities. For an entity that only has end of the line equipment involved in the scheme,
such as breaker trip coils, too much obligation falls on this entity that has a minor role. A large number of entities will fall into the
category of owning a very small supporting portion of a RAS scheme and who do not have the means (information they do not control or
determine) to perform the required reporting. Differentiation should be made between the primary RAS-entity (owner of a RAS scheme,
primary) and owners of pieces of equipment who play a minor role for the primary RAS scheme. The standard should be rewritten to
differentiate between primary and secondary (minor) to clarify roles and responsibilities.
As was mentioned in previous draft comments by others, this standard works great when there is one entity that owns the entire
scheme. R3, R5, R6, R7, and R8 should be revised to designate overall responsibility to an owner of the scheme, with all secondary (minor
participants) involved in the scheme being required to support the owner of the scheme in their development and reporting obligations.
The primary RAS-entity that designs, owns and controls the RAS should be the one responsible for coordinating and meeting these
requirements from the standard.
Other possible implications:
City Light additionally suggests that the term RAS-entity only apply to this standard and not be placed in the Glossary of Terms. If City
Light is labeled as a RAS-entity under this current drafted definition, we would be defined as owning some or all of a RAS. There are no
approved definitions for a RAS Owner. Project 2010-05.3 PRC-012-2 RAS Seattle City Light Comments Additional Ballot and Non-Binding
Poll March 16, 2016
Other standards that assign RAS responsibilities do so under the applicability verbiage of “XXXX that owns an SPS”. City Light feels this
would impose undue confusion and compliance responsibility on entities that are minimally involved in a RAS. Therefore, RAS Entity
should be only applicable to this standard.
We suggest adding the below defined term and language which would help serve three purposes. First to clarify who has responsibility
for certain aspects of this standard. Secondly, to help clarify which entity has responsibility under current and future enforced RAS
related standards such as PRC-017-1. Lastly, the proposed term would align with current WECC assignments of RAS responsibility.
Consideration of Comments | 2010-05.3 Phase 3 of Protection Systems: RAS | PRC-012-2
April 20, 2016
18
RAS-owner—the Transmission Owner, Generator Owner, or Distribution Provider that is the majority owner and operator of a RAS, this is
normally identified using the following prioritization;
The RAS-owner is the Transmission Owner of the scheme. Where there is not a Transmission Owner that owns a portion of the RAS, the
Generator Owner becomes the RAS-owner. Where there is not a Transmission Owner or a Generator Owner that owns a portion of the
RAS, the Distribution Provider becomes the RAS-owner.
In conclusion, revising the standard to clarify roles and responsibilities between the primary and secondary (participants) is crucial to the
successful implementation of this standard when RAS components are owned by multiple entities.
Thanks you for your time and efforts in developing a successful standard
Likes
0
Dislikes
0
Response
Thank you for your comments.
The term RAS-entity is applicable to PRC-012-2 only and will not be included in the Glossary of Terms Used in NERC Reliability Standards.
For purposes of PRC-012-2, the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part of a RAS is a RASentity as defined in the Applicability. The RAS-entity is responsible to participate in the various activities identified by the requirements to
the extent of its ownership. RAS-entities have the option of collaborating to fulfill their responsibilities for each applicable requirement;
however, the individual RAS-entity must be able to demonstrate its participation for compliance purposes.
The drafting team is charged with assigning the requirements of the new standard to the specific users, owners, and operators of the
Bulk‐Power System while incorporating the reliability objectives of all the RAS‐related standards. In drafting this standard, the drafting
team has worked diligently to minimize the changes that will be required from the existing processes. The drafting team recognizes that
RAS with multiple owners inherently require coordination among all the participating RAS-entities from the first conceptual design
through construction to operations, testing, maintenance and retirement.
For purposes of PRC-012-2, when a RAS has more than one owner, each RAS-entity is obligated to participate in the various activities
identified by the requirements to the extent of its ownership. Collaboration, coordination, and communication between and among
entities regarding RAS issues helps to ensure efforts are not duplicated and best serves reliability by promoting awareness. For purposes
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of creating efficiencies, the drafting team maintains registered entities that currently share ownership of a RAS (RAS-entities) are in some
manner already communicating, sharing information, and coordinating RAS tasks such as operations analysis, Corrective Action Plan
(CAP) development, and functional testing. The drafting team is confident that entities will continue to do this after this standard is
effective and that entities will communicate with each other if there is any question or doubt of responsibility surrounding any
requirement.
The drafting team contends that your proposed language would cause confusion and declines to make the suggested changes.
Christy Koncz - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG
Answer
No
Comment
Requirement 1 – There are no clear lines of responsibility for jointly owned RASs.
The concept of a RAS-entity causes RAS-entity causes confusion for entities that have joint ownership of a RAS. While the SDT recognizes
this issue by stating: “ Ideally, when there is more than one RAS‐entity for a RAS, the RAS‐entities would collaborate and submit a single,
coordinated Attachment 1to the reviewing RC”. While PSEG agrees with the intent of this statement, it is included in the “Rationale”
section of the draft standard and therefore that language will not be incorporated into the final standard. Furthermore, PSEG believes
that PSEG that the language of R1 would still require each RAS entity to submit all information in Attachment 1to the Reliability
Coordinator, which is inconsistent with the Paragraph 81 effort and the Reliability Assurance Initiative. PSEG believes such intent could
be incorporated in to R1 as follows:
R1. Prior to placing a new or functionally modified RAS in‐service or retiring an existing RAS, each the RAS‐entity shall provide the
information identified in Attachment 1 for review to the Reliability Coordinator(s) where the RAS is located. If there are multiple RASentities, the entities may delegate a single mutually agreeable RAS-entity to submit Attachment 1 on their behalf.
PSEG wishes to note that such language would not be useful in situations where the one or more of the RAS-entities that jointly own a
RAS do not want to cooperate or cannot agree upon a single lead entity. Additionally, PSEG believes that a single entity (either the
Reliability Coordinator or the Planning Coordinator) should be responsible for coordinating the RAS entities.
Attachment 1 – Attachment 1 should have defined roles for the Planning Coordinator (PC) or Transmission Planner (TP).
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Since the requirement for new and revised remedial action schemes are likely to be initiated by the results of Transmission system
planning performance assessments done by the TP or PC in compliance with TPL-001-4, one of those entities would be best suited to
perform many of the activities listed under section II of Attachment 1.
Furthermore, the technical studies that are required by Attachment 1 should not be performed individually by each RAS-entity because
they do not have the skills or tools available to perform such analyses. For example, if an independent generator is asked by its RC to
implement a run-back scheme to resolve a stability issue, it is unlikely that that entity would have to tools available to provide the
information required under Attachment 1, item II.6.
Rather, PSEG recommends that the RAS-entities’ PC or (TP) conduct the assessment of the System performance of a proposed new,
modified, or retired RAS. Under this construct a RAS-entity implementing a new, modified, or retired RAS would submit an application
under R1 containing general information as well as details concerning the proposed components and logic of the RAS to its TP or PC and
to other RAS-entities that would participate in the RAS The PC or TP in turn would conduct the assessment of the proposed RAS to
determine if the proposed RAS resolves the System performance issues, and forward that information to the RC for consideration under
Requirement 2.
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Pragna Pulusani, N/A, Pulusani Pragna; PSEG - PSEG Energy Resources and Trade LLC, 6, Jara
Karla
0
Response
Thank you for your comments.
The drafting team declines to make the suggested change to Requirement R1. When this standard receives Board adoption, the Rationale
boxes will be moved to the Supplemental Material section and will remain with the standard. PRC-012-2 is a results-based standard and
not a prescriptive one; it is not the intent of the drafting team to specify how multiple RAS‐entities must collaborate or coordinate. The
drafting team is confident that entities will continue to communicate and work with each other as they do now. The drafting team
maintains that the RAS‐entity has the “flexibility” to request information or assistance from relevant entities (third parties)
The drafting team maintains that the RC is the functional entity best suited to perform the RAS review because it has the widest area
perspective of all functional entities and minimizes the possibility of a conflict of interest that could exist because of business
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relationships among the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP), or other entities that are likely to be involved
in the planning or implementation of a RAS.
The drafting team agrees that the PC and/or TP would participate in providing Attachment 1 information. It is anticipated that the
associated studies will likely be performed, in whole or in part, by the TP or PC; the RAS-entity is required only to provide the compiled
Attachment 1 information.
Greg Davis on Behalf of Jason Snodgrass, Georgia Transmission Corporation - 1
Answer
No
Comment
GTC Background:
There are multiple registered Planning Coordinators and jointly shared transmission system in GTC’s Planning Area and it is important for
each PC in the area to be notified prior to placing new or functionally modified RAS in-service or retiring an existing RAS. Equally as
important, is for each PC in the area to be notified if CAP actions or timetables change when the CAP is completed pursuant to CAPs
developed for R6. GTC’s proposed considerations listed below are focused on mitigating operational and compliance risks associated
with awareness and knowledge of new or functionally modified RAS where there are multiple registered PCs in a common RC Area.
R7.3:
Although R4.2 requires each impacted TP and PCs to be notified of results of a RAS evaluation, there is not a similar method for any
impacted TP and/or PC to be notified in which a RAS was evaluated with identified deficiencies pursuant to CAPs developed for R6; nor
when or if CAP is implemented in a timely manner or if timetables change. We propose including the phrase “and Planning Coordinators
within the RAS-entity’s area” in R7.3, which would read as follows: “Notify each reviewing Reliability Coordinator and Planning
Coordinators within the RAS-entity’s area, if CAP actions or timetables change and when the CAP is completed.”
R9:
Even though it seems implied in R9 that the RAS database containing all pertinent data will be made available to impacted PCs and/or TPs
in the RCs area, it is unclear. GTC proposes the following new requirement to compliment the obligations of the Planning Coordinator
under requirement R4 if the aforementioned proposed changes to R7.3 are not adopted by the SDT.
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R10 (proposed new requirement): Each Reliability Coordinator shall provide each Planning Coordinator in their Reliability Coordinator
area a copy of the RAS database maintained in accordance with R9, at least once every twelve full calendar months.
R4.1.5:
Since a RAS is only required when the performance requirements of TPL-001-4 will not be met, is R4.1.5 essentially mandating
redundancy for all RAS components? What does a single component failure constitute under Requirement R 4.1.5?
Clarification of limited impact RAS:
SERC DRS suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS
considered to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be
experienced by just one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or
unreliable BES, and we do not believe that this should remove an RAS from limited impact consideration.
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Response
Thank you for your comments.
R7.3 comment: The notification of changes regarding CAP actions, timetables, or completion has a more immediate effect on the
operation of the System rather than the planning of the System; therefore the standard requires the RC be notified of these changes.
Because the RC is responsible for the reliability of the BES in its RC Area, the drafting team maintains that the RC has a vested interest in
sharing pertinent data with functional entities that have reliability-related needs.
R9 comment: The drafting team contends that an additional requirement is not necessary, because as stated in the Rationale for
Requirement R9, the RC can provide other functional entities (e.g. Transmission Operators and Planning Coordinators) high-level
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information/data on existing RAS that could potentially impact the operational and/or planning activities of that entity. Because the RC is
responsible for the reliability of the BES in its RC Area, the drafting team maintains that the RC has a vested interest in sharing pertinent
data with functional entities that have reliability-related needs.
R4.1.5 comment: The drafting team disagrees that a RAS is required when the performance requirements of TPL-001-4 will not be met; a
RAS is one possible solution to resolve that issue. Requirement R4, Part 4.1.5 requires the PC to periodically perform an evaluation of
each RAS within its planning area to determine whether, except for limited impact RAS, a single component failure in the RAS, when the
RAS is intended to operate does not prevent the BES from meeting the same performance requirements (defined in Reliability Standard
TPL-001-4 or its successor) as those required for the events and conditions for which the RAS is designed. Requirement R4, Part 4.1.5
does not mandate that all RAS have redundant components. For example, consider the instance where a RAS is installed to mitigate an
extreme event in TPL-001-4. There are no System performance requirements for extreme events; therefore, the RAS does not need
redundancy to meet the same performance requirements as those required for the events and conditions for which the RAS was
designed. A single component failure would be the failure of any one of the components of a RAS. A list of individual components is not
practical given the variety that could be applied in RAS design and implementation. See Item 4a in the Implementation Section of
Attachment 1 in the Supplemental Material section for typical RAS components for which a failure may be considered.
The drafting team avoids the use of adjectives such as “widespread” because of the ambiguity those terms introduce. The drafting team
maintains that the “BES” qualifier in the statement regarding the limited impact designation modifies all of the conditions that follow; i.e.,
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, and unacceptably damped oscillations. As
you suggest, the instability of a single generating unit or small generating plant would not be indicative of an unstable or unreliable BES;
however, the RC is the final arbiter for determining whether the RAS qualifies for limited impact status based upon review of the
Attachment 1 information.
Ben Engelby - ACES Power Marketing - 6, Group Name ACES Standards Collaborators - PRC-012-2 Project
Answer
No
Comment
RAS-entity causes confusion for entities that have joint ownership of a RAS. We recommend the SDT develop guidance to support
the requirements and expectations for joint owners to meet compliance. For RAS with multiple RAS-entities, who is responsible
for overall coordination to assure complete and consistent data submittals in order to meet compliance with this standard?
2. For R2, we remain concerned by the term “mutually agreeable” and how it will be applied.
1.
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Why did the SDT give the RC the authority to determine “limited impact” RAS without providing objective criteria or
guidelines? The SDT cited Local Area Protection Scheme (LAPS) in WECC and the Type 3 designation in NPCC. What about the
other regions? There should be a specific set of parameters for the RC to make a decision. We suggest developing continent-wide
criteria for determining limited impact RAS and not referring to only two regional approaches.
4. Why does the SDT include “limited impact” RAS as being applicable to the standard? If it has a limited impact, then it should not
apply at all. This proposal by the SDT is contrary to the past two years of NERC’s RAI and RBR initiatives focusing on HIGH RISK
activities. By definition, “limited impact” should not matter for BES reliability. The limited impact designation creates
unnecessary compliance burdens without a clear benefit to increased reliability of the BES.
3.
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Response
Thank you for your comments.
PRC-012-2 is a results-based standard and not a prescriptive one; it is not the intent of the drafting team to specify how multiple RAS‐
entities must collaborate or coordinate. The drafting team is confident that entities will continue to communicate and work with each
other as they do now. For purposes of PRC-012-2, the Transmission Owner, Generator Owner, or Distribution Provider that owns all or
part of a RAS is a RAS-entity as defined in the Applicability. The RAS-entity is responsible to participate in the various activities identified
by the requirements to the extent of its ownership. RAS-entities have the option of collaborating to fulfill their responsibilities for each
applicable requirement; however, the individual RAS-entity must be able to demonstrate its participation for compliance purposes.
The time frame of four full calendar months for RAS reviews is consistent with current utility and regional practices. The drafting team
wrote the requirement to permit either shorter or longer time intervals for a RAS review provided all the affected parties agreed to the
alternate time.
The drafting team maintains that the RC is the functional entity best suited to perform the RAS reviews because it has the widest area
reliability perspective of all functional entities and an awareness of reliability issues in neighboring RC Areas. This Wide Area purview
facilitates the evaluation of interactions among separate RAS as well as interactions among the RAS and other protection and control
systems. Because the RC has the most comprehensive operational knowledge of the BES in its RC Area, the drafting team contends the
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RC, armed with the studies and other information provided with the Attachment 1 submittal, is capable of making a well-reasoned
determination of a RAS, including whether it qualifies for the limited impact designation.
WECC and NPCC were cited because those are the only two Regions that classified RAS based upon certain criteria. The SPCS-SAMS team
also recognized these Regional classifications and made similar albeit different recommendations. The drafting team considered the
attributes of each of these Regional classifications in creating the guidance for limited impact designation. The limited impact designation
is applicable on a continent-wide basis via NERC Reliability Standard PRC-012-2.
While a limited impact RAS presents a lower risk to BES reliability, the limited impact designation should not be construed as zero impact
or risk. PRC-012-2 is applicable to all RAS under the new FERC approved RAS definition. In addition, System changes could occur to cause
a RAS to no longer qualify as limited impact so the designation is not permanent. Please reference Requirement R4, Part 4.1.3. The
drafting team disagrees with your premise regarding the compliance burden. The RAS-entity is not obligated to request a RAS be
considered for limited impact designation; i.e., provide the necessary analyses and/or studies to demonstrate that the RAS should be
considered limited impact.
Teresa Czyz - Oglethorpe Power Corporation - 5
Answer
No
Comment
OPC agrees with GTC's comments:
There are multiple registered Planning Coordinators and jointly shared transmission system in GTC’s Planning Area and it is important for
each PC in the area to be notified prior to placing new or functionally modified RAS in-service or retiring an existing RAS. Equally as
important, is for each PC in the area to be notified if CAP actions or timetables change when the CAP is completed pursuant to CAPs
developed for R6. GTC’s proposed considerations listed below are focused on mitigating operational and compliance risks associated
with awareness and knowledge of new or functionally modified RAS where there are multiple registered PCs in a common RC Area.
R7.3:
Although R4.2 requires each impacted TP and PCs to be notified of results of a RAS evaluation, there is not a similar method for any
impacted TP and/or PC to be notified in which a RAS was evaluated with identified deficiencies pursuant to CAPs developed for R6; nor
when or if CAP is implemented in a timely manner or if timetables change. We propose including the phrase “and Planning Coordinators
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within the RAS-entity’s area” in R7.3, which would read as follows: “Notify each reviewing Reliability Coordinator and Planning
Coordinators within the RAS-entity’s area, if CAP actions or timetables change and when the CAP is completed.”
R9:
Even though it seems implied in R9 that the RAS database containing all pertinent data will be made available to impacted PCs and/or TPs
in the RCs area, it is unclear. GTC proposes the following new requirement to compliment the obligations of the Planning Coordinator
under requirement R4 if the aforementioned proposed changes to R7.3 are not adopted by the SDT.
R10 (proposed new requirement): Each Reliability Coordinator shall provide each Planning Coordinator in their Reliability Coordinator
area a copy of the RAS database maintained in accordance with R9, at least once every twelve full calendar months.
R4.1.5:
Since a RAS is only required when the performance requirements of TPL-001-4 will not be met, is R4.1.5 essentially mandating
redundancy for all RAS components? What does a single component failure constitute under Requirement R 4.1.5?
Clarification of limited impact RAS:
SERC DRS suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS
considered to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be
experienced by just one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or
unreliable BES, and we do not believe that this should remove an RAS from limited impact consideration.
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Response
Thank you for your comments.
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Please see the drafting team’s responses to the referenced comments.
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
No
Comment
Requirement 4 of the standard puts the burden of performing the studies on the PC. PNM as a registered PA/PC doesn’t contest the
assignment of the requirement to the PC; however, the standard doesn’t guarantee that the PC will be provided with the data required
to perform the assessment. PNM proposes adding a requirement for the RAS entity to provide data required to assess the RAS within 30
calendar days of receiving approval from the RC so that the PC can obtain the information required to adequately assess each scheme
every five full calendar years. The information provided to the RC in R5.2, R6, R7.3 would impact the R4 assessment; therefore, the PC
should also be receiving this information.
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Response:
Thank you for your comments.
The drafting team maintains that the RAS-entity has a vested interest in getting the Requirement R4 review completed on time and will
therefore provide the data to the PC without being mandated by a requirement. The notification of changes regarding CAP actions,
timetables, or completion has a more immediate effect on the operations of the System versus the planning of the System; therefore the
standard requires the RC be notified of these changes. Because the RC is responsible for the reliability of the BES in its RC Area, the
drafting team maintains that the RC has a vested interest in sharing pertinent data with functional entities that have reliability-related
needs. The drafting team declines to make the suggested change.
Jared Shakespeare - Peak Reliability - 1
Answer
No
Comment
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What is the required evaluation for the PC in R4? For the RC it is clear to follow Attachment 2 for the evaluation but the PC in R4 does not
have any explicit evaluation requirement. We recommend adding language that describes the PC adhering at a minimum, but not limited
to, Attachment 2 for their 5 year evaluation.
Both R4.1.4 and Attachment 1, section III, item 4 use the same language, “a single component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from meeting the same performance requirements (defined in Reliability Standard TPL‐
001‐4 or its successor) as those required for the events and conditions for which the RAS is designed.” Though similar language is used in
the currently effective set of reliability standards, it is confusing and unclear. We recommend providing examples in an application
guideline as part of the standard itself that might help the reader understand the meaning of and intent behind this language.
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Response:
Thank you for your comments.
The drafting team maintains that Requirement R4 provides the desired reliability objectives without being prescriptive or explicit
regarding the methodologies used to attain them. The review of Requirement R2 focuses on the design and implementation aspects of
the RAS whereas the periodic evaluations of Requirement R4 are focused on the planning analyses and System impacts related to the
RAS. While aspects of Attachment 2 could be used by the PC during its evaluations, the drafting team disagrees with the suggestion to
require the use of Attachment 2 in Requirement R4.
The drafting team provided examples in the Supplemental Material section for Requirement R4 as you requested.
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
No
Comment
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Duke Energy suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS
considered to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably
damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be
experienced by just one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or
unreliable BES, and we do not believe that this should remove an RAS from limited impact consideration.
Duke Energy also reiterates its concern regarding the compliance implications of potentially requiring the RC to be responsible for the
technical correctness of an RAS-entity’s information it provides in Attachment 1. An RC should only be held responsible for the “wide area
purview” or conceptual appropriateness of a new or functionally modified RAS, and not be held responsible for potential mistakes made
by the RAS-entity during the process.
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Response
Thank you for your comments.
The drafting team avoids the use of adjectives such as “widespread” because of the ambiguity those terms introduce. The drafting team
maintains that the “BES” qualifier in the statement regarding the limited impact designation modifies all of the conditions that follow; i.e.,
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, and unacceptably damped oscillations. As you
suggest, the instability of a single generating unit or small generating plant would not be indicative of an unstable or unreliable BES;
however, the RC is the final arbiter for determining whether the RAS qualifies for limited impact status based upon review of the
Attachment 1 information.
The RC cannot, under Requirement R2, be held responsible for the technical correctness of a RAS-entity’s information but only that a
review covering the items in Attachment 2 has been accomplished. It is possible and certainly desirable that a RC might uncover errors in
a RAS-entity’s information during a review exercised with appropriate diligence, but not a requirement.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
No
Comment
Would suggest the drafting team develop a Standards Authorization Request (SAR) for the term ‘limited impact’ and propose the term be
added to the NERC Glossary and Rules of Procedure (RoP) to promote consistency and clarity. During our current evaluation of this draft
of the Standard and RSAW, we are concerned that the Rationale box information (page 5 of the Standard-next to the sentence) is not
consistent with the Requirement R4 sub-part 4.1.3. Another concern is that we feel the sub-part states the proposed definition of ‘limited
impact’ twice. At the first use, the term ‘limited impact’ is stated with a footnote-4 “A RAS designated as ‘limited impact’ cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations” then this same information is stated again after the term. We suggest
the drafting team use some different language besides “verify the limited impact designation remains applicable” which was stated in the
Rationale box in order to make it clear just what the SDT intends the reviewer to do.
Additionally, we interpret that in the RSAW (note to Auditor-Section Requirement R4) there is an attempt to define the term ‘Inadvertent
operation’. If this is the case, we would suggest the review panel/drafting team should develop a SAR for that particular term and
propose that it be included in the NERC Glossary of Terms and Rules of Procedure (RoP) as well as including that term in the Standard
again to promote consistency and clarity.
For Requirement R6, we have a concern that the translation of the Rationale and Technical data (in the Standard) and the Note to Auditor
information (in the RSAW) may become lost. As we have evaluated both documents, it seems more evident that the Rationale and
Technical information needs to be included in the RSAW. This information has been included in the Standard to help provide a solid
foundation to each Requirement to help support the auditing process. However, this information isn’t included in the RSAW which leads
to potential inconsistency in the auditing process. We feel that both documents need to contain the same information in order to be
properly aligned.
Finally, our last concern would be having all maintenance requirements implemented into one document. Currently, we agree that
Requirement R8 pertains to performing maintenance associated with Functional Testing as well as verifying proper operation of nonprotection system components (system maintenance). However, we suggest moving Requirement R8 into the PRC-005 Standard for
consistency in reference to maintenance requirements.
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Response
Thank you for your comments.
The drafting team maintains that the general description and explanatory language regarding the limited impact designation does not rise
to the level of a definition that should be included in the Glossary of Terms Used in NERC Reliability Standards; instead, it provides highlevel guidance for the RC to consider during the RAS review. The drafting team notes that the commenter has the correct understanding
of Requirement R4, Part 4.1.3 that the Planning Coordinator must verify the limited impact designation remains applicable for each RAS
previously designated as such. The drafting team prefers to keep the existing language and therefore declines to make the suggested
change.
The RSAW is a document used as a guide for auditors to assess compliance with the standard and includes the statement: “Inadvertent
operation refers to an operation of the RAS when the RAS is not intended to operate.” The drafting team maintains the dictionary
definition of the term “inadvertent,” which is “not intended or planned” is clear and unambiguous.
Information in the Rationale boxes and Supplemental Material section of the draft standard is important to explain the foundation for
each requirement of the standard; whether or not that same information is included in the RSAW is not the drafting team’s decision. The
determination of the final RSAW content belongs to the RSAW Task Force, the Regional Entities and NERC compliance groups. The draft
RSAW will be reviewed by the RSAW Task Force and all comments submitted on the RSAW will be evaluated prior to the RSAW being
finalized.
The drafting team appreciates your understanding of the fundamental differences between the functional testing of RAS (performance
evaluation of the scheme) versus maintenance of Protection System (maintaining components; i.e., relays, etc.). The drafting team
contends that Requirement R8 should remain in PRC-012-2, as is.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Comment
The list of qualifications for the designation of limited impact states that a limited impact RAS cannot cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. The
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term angular instability needs to be clarified further. Currently it implies that if the RAS was installed to prevent a 40 MW generator from
becoming unstable, then it cannot be designated as limited impact. The term should be qualified as follows: system angular instability.
This would give the RC the leeway to judge that a small unit going unstable would not negate the designation limited impact.
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Response
Thank you for your comments.
The drafting team avoids the use of adjectives such as “widespread” because of the ambiguity those terms introduce. The drafting team
maintains that the “BES” qualifier in the statement regarding the limited impact designation modifies all of the conditions that follow; i.e.,
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, and unacceptably damped oscillations. As you
suggest, the instability of a single generating unit or small generating plant would not be indicative of an unstable or unreliable BES;
however, the RC is the final arbiter for determining whether the RAS qualifies for limited impact status based upon review of the
Attachment 1 information.
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Comment
ERCOT is supportive of the “limited impact” RAS designation, and is also supportive of a periodic evaluation of RAS to determine if these
still qualify for the limited impact designation. However, ERCOT disagrees with the language of requirement subpart 4.1.3.
Clarification on the intention of 4.1.3 in this context is requested. A Planning Coordinator (PC) with limited impact RAS (ex. a RAS set up
to reduce BES flows by ramping down or tripping generation) should be allowed discretion to utilize screening studies as a threshold test
to determine the necessity of evaluating a RAS for uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations. For limited impact RAS that only have local impacts, 4.1.3 as written requires costly and unnecessary
studies. ERCOT suggests that the SDT consider imposing a MW threshold for each interconnection below which the PC would be required
to conduct only a power flow study. Alternatively, ERCOT requests clarification—in either 4.1.3 itself or in the rationale—that the PC has
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discretion in the type of studies it can use to satisfy the evaluations required to determine if the reliability impact of the RAS has changed
over time.
ERCOT also asks for clarification on the “Supporting Documentation for RAS Review” in Attachment 1. The introductory statement in
Attachment 1 implies that the Reliability Coordinator (RC) has discretion in determining exactly what information it would like to receive
from an RAS-entity with the statement “If an item on this list does not apply to a specific RAS, a response of “Not Applicable” for that
item is appropriate.” The RAS-entity and the RC typically work together to determine what is required to approve an SPS or a RAS. The
RC’s discretion in determining what information a RAS-entity must submit under Attachment 1 is sufficient for the evaluation of the RAS.
ERCOT suggests the SDT make the RC’s discretion explicit through the following language modification to the Attachment 1 introduction:
“The following checklist identifies important Remedial Action Scheme (RAS) information for each new or functionally modified RAS that
the RAS-entity must document and provide to the reviewing Reliability Coordinator(s) (RC), as required by the RAS-entity’s Reliability
Coordinator”
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Response
Thank you for your comments.
PRC-012-2 is a results-based standard and not a prescriptive one; it is not the intent of the drafting team to specify how the PC provides
the desired reliability objective of Requirement 4, Part 4.1.3. The PC can use its discretion regarding the methodology used to evaluate
the RAS. The drafting team modified the Rationale for Requirement R4 to state: “Requirement 4, Part 4.1.3 explicitly requires the periodic
evaluation of limited impact RAS to verify the limited impact designation remains applicable; the PC can use its discretion as to how this
evaluation is performed.”
The drafting team maintains that the RAS-entity can decide what information in Attachment 1 is “Not Applicable.” For example, Item II.4
concerns “Information regarding any future System plans that will impact the RAS.” The RAS-entity may not have any future plans which
impact the RAS; therefore, a response of “Not Applicable” is appropriate for this item. The drafting team declines to make the suggested
change.
Andrew Pusztai - American Transmission Company, LLC - 1
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Answer
No
Comment
ATC has several recommendations for improvement or clarification on the draft Standard, for consideration by the SDT as listed below:
•
R4.1.3 and R4.1.4 – These requirements refer to ‘single component malfunction’ and ‘single component failure’ respectively.
However, the standard does not contain any identification or clarification of which types of components must be included and
which may be excluded in RAS evaluations. This deficiency could be addressed by including text in the Supplemental Material
section under Requirement 4 that the drafting team developed for a response in its Consideration of Comments for Draft 1 of
PRC-012-2.
“An exhaustive list of components is not practical given the variety that could be applied in RAS design and implementation. See Item
4a in the Implementation Section of Attachment 1 in the Supplemental Material section for typical RAS components for which
redundancy may be considered. The RAS‐entity should have a clear understanding of what components were applied to put a RAS
into service and which were already present in the system before a RAS was installed. The RC will make the final determination
regarding which components should be regarded as RAS components during its review”.
•
R5 – This requirement does not obligate RAS-entities to provide their results of the operational performance analysis of a RAS
event to impacted Transmission Planners and Planning Coordinators. However, this action should be proposed in the
Supplemental Material section.
•
R6 – This requirement does not obligate RAS-entities to provide their Corrective Action Plans to impacted Transmission Planners
and Planning Coordinators. However, this action should be proposed in the Supplemental Material section.
•
R8 - The purpose of Version 6 of PRC-005 was to consolidate all maintenance and testing of relays under one Standard. Having
RAS testing within PRC-012-2 would be contrary to that end. ATC proposes to address this concern as follows:
Functional testing of RAS (as stated in Requirement 8 of PRC-012-2) is a maintenance and testing activity that would be better included in
the PRC-005 standard. The present PRC-005-6 Reliability Standard is the maintenance standard that replaces PRC-005-1, 008, 011 and
017 and was designed to cover the maintenance of SPSs/RASs. However, the current Reliability Standard PRC-005-6 lacks intervals and
activities related to non-protective devices such as programmable logic controllers. ATC recommends that a requirement for
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maintenance and testing of non-protective RAS components be added to a revision of PRC-005-6, rather than be an outlying maintenance
requirement located in the PRC-012-2 Standard.
If the requirement is not removed and placed in PRC-005 standard, then we suggest that wording be added to R8 to refer the entity to
meet the maintenance and testing interval obligations in the latest version of the PRC-005 standard.
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Response
Thank you for your comments.
The drafting team included language as you suggested in the Supplemental Material section of the draft standard for Requirement R1. It
is not the intent of Requirement R4 that the PC performing the evaluation examine the physical implementation of the RAS, but rather to
assess the System impacts of a failure to operate or an inadvertent operation. If redundant components were used to implement the RAS
such that a single component failure would not prevent the RAS from operating, this would be confirmed by the RC during the initial
review and then verified by subsequent functional testing, and should not need to be re-examined during the periodic evaluation per
Requirement R4. However, if the RAS is designed to meet the “failure to operate” or “inadvertent operation” objectives by over-arming
of load or alternate actions, the continued effectiveness of these alternative actions should be evaluated.
There is nothing in the standard preventing the RAS-entity from sharing the results of its operational analysis with their TP or PC. It is
anticipated that in many cases, the TP or PC will be involved in performing the analysis. The Rationale for Requirement R5 notes that RASentities may need to collaborate with their associated Transmission Planner to comprehensively analyze RAS operational performance.
The drafting team declines to make the suggested change.
There is nothing in the standard preventing the RAS-entity from sharing its CAP with their TP or PC. It is anticipated that in many cases,
the TP or PC will be involved in developing the CAP. The Rationale for Requirement R6 notes that the RAS-entity may request assistance
with CAP development from other parties such as its Transmission Planner or Planning Coordinator. The drafting team declines to make
the suggested change.
As stated in the current version of PRC-005-6, the purpose of the Standard is: “To document and implement programs for the
maintenance of all Protection Systems, Automatic Reclosing, and Sudden Pressure Relaying affecting the reliability of the Bulk Electric
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System (BES) so that they are kept in working order.” The only applicability for RAS components in the current version is under the
Facilities section 4.2.4 with “Protection Systems installed as a Remedial Action Scheme (RAS) for BES reliability”. As a result, PRC‐005-6 is
not applicable to non‐Protection System components, such as RAS controllers. The drafting team has identified various components that
may be used in RAS that are not Protection Systems, such as programmable logic controllers (PLCs), personal computers (PCs), multi‐
function programmable relays used as a PLC, remote terminal units (RTUs), and logic processors.
Given the potential impact RAS may have on the BES, the drafting team contends that functional testing is necessary to maintain BES
reliability. The reliability objective of Requirement R8 is to maintain the non‐Protection System components of a RAS; i.e., the controllers
(programmable logic controllers (PLCs), personal computers (PCs), multi‐function programmable relays, remote terminal units (RTUs),
and logic processors), and to verify the overall performance of the RAS through functional testing. Functional tests validate RAS operation
by ensuring System states are detected and processed, and that actions taken by the controls are correct and occur within the expected
time using the in‐service settings and logic (functional testing by default operates the processing logic and infrastructure of a RAS).
Functional testing should not be confused with the component focused maintenance of PRC‐005 Protection System Maintenance. PRC‐
005 is not applicable to non‐Protection System components such as RAS controllers. RAS designated as limited impact have functional
testing intervals of up to twelve full calendar years. However, all other RAS have up to six full calendar year intervals because of the
higher risk they pose to negatively impact BES reliability should they operate incorrectly or fail to operate. The drafting team recognizes
that PRC‐005 extends the maintenance interval for monitored multifunction programmable relays to twelve calendar years; however, the
drafting team asserts that the inadvertent operation or failure of a RAS subject to the six year functional test interval poses too much risk
to the reliability of the BES to extend the test interval beyond six years.
Douglas Webb on Behalf of Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co. - 3, 6, 5, 1
Answer
No
Comment
Kansas City Power & Light Company appreciates this opportunity to share its comments regarding concerns the company has with the
proposed revisions to the Standard.
As used in the proposed revisions to Standard PRC-012-2, the term “limited impact” creates an ambiguous enforceable provision and
needs to be a defined NERC Glossary term to establish a clear compliance threshold.
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The Standard Drafting Team (SDT) is empowered by the NERC Standards Process Manual (SPM) to “…propose to add, modify, or retire a
defined term in conjunction with the work it is already performing.” SPM, Sec. 5 Preamble. We respectfully request the SDT exercise that
authority to define “limited impact” for the following reasons.
“Limited impact” establishes an enforceable provision: The proposed revisions use “limited impact” in the language of the Requirements
and attachments to the Standard that are incorporated by reference. By the regular use of the term, and the context in which it is used, a
conclusion is easily drawn: The term is material to the Standard and required to evaluate compliance and, ultimately, enforcement of the
Standard.
“Limited impact” creates an uncertain compliance obligation: The term “limited impact” is undefined and ambiguous and, as such,
creates uncertainty in an entity’s compliance obligation. The word “limited” suggests a range of values. When used with “impact,” the
range of values is used to affect the determination of the degree of impact. The proposed revisions to the Standard seek to establish the
range of values in multiple ways. First, by referencing information found in the stated underlying source of the term, WECC and NPCC
classification schemes; secondly, offering an explanation what is intended by the term; third, explaining what the term is not intended to
reflect; and, lastly, a lengthy discourse on the term, as found in the Attachments. Taken together, all the information may seem to
provide guidance as to the meaning of the term, “limited impact,” but in the end the term remains undefined and creates a compliance
obligation that is unclear and promotes a spectrum of interpretations as to what values fall within the “limited” range.
Policy promotes relevant Regional Defined Terms be considered for the NERC Glossary Term: The NERC Standards Process Manual
(SPM) states:
“Some NERC Regional Entities have defined terms that have been approved for use in Regional Reliability Standards, and where the
drafting team agrees with a term already defined by a Regional Entity, the same definition should be adopted if needed to support a
NERC Reliability Standard.” SPM Sec. 5.1.
The proposed revisions to the Standard provide that the source of the term “limited impact” is taken from the WECC and NPCC
classification schemes. Whether the term is a regionally defined term by WECC and NPCC or not, the spirit of the SPM is to apply terms
equally, that if a term is used by Regional Entities in a North American Standard, then it is appropriate for the term be considered for
adoption as a defined term to support that Standard.
Below is a Catalog of the Term “limited impact” as used in Proposed PRC-012-2 Standard
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The Standard’s language uses “limited impact” in Requirements R4 and R8, and multiple times in the three attachments that are
incorporated by reference in the Standard.
WECC and NPCC Classification Schemes—R4 Rationale cites to the WECC and NPCC classification schemes as how the “…limited impact
designation is modeled…;” Technical Justification for the term “limited impact” states, “Because the drafting team modeled the limited
impact designation after the WECC and NPCC classifications…”
Description of what the term, “limited impact,” is not—R4.1.3. Footnote to “limited impact.” See also Att. 1, Sec. I.4.g Footnote to
“limited impact”; Att. 2, Sec. I.6 Footnote to “limited impact”; Att. 3, Sec. 7 Footnote to “limited impact”; Technical Justifications for
Attachment 1 Content Supporting Documentation for RAS Review, Sec. I.4.g Footnote to “limited impact”; Technical Justifications for
Attachment 3 Content, Sec. 7 Footnote to “limited impact.”
“Limited impact” Citations in Standard—The use of the term “limited impact” in R4; R8; Att. 1, Sec. I.4.g; Att. 1, Sec. II.5; Att. 1, Sec. II.6;
Att. 1, Sec. III.4; Att. 2, Sec. I.6; Att. 2, Sec. I.7; Att. 2, Sec. II.2; Att. 3, Sec. 7; Supplemental Material, R4, R8; Technical Justifications for
Attachment 1 Content Supporting Documentation for RAS Review, Sec. I.4.g, Sec. II.5, Sec. II.6, Sec. III.4; and Technical Justifications for
Attachment 3 Content, Sec. 7.
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Response
Thank you for your comments.
The drafting team disagrees with the premise that the term limited impact creates an ambiguous enforceable provision and should be a
defined term in the Glossary of Terms Used in NERC Reliability Standards. The drafting team maintains that the general description and
explanatory language regarding the limited impact designation does not rise to the level of a definition that should be included in the
Glossary of Terms Used in NERC Reliability Standards; instead, it provides high-level guidance for the RC to consider during the RAS
review. The Reliability Coordinator has responsibility for the reliability of BES operations within its RC Area and consequently has the
responsibility to review and approve each RAS before it is implemented in its RC Area. Furthermore, the RC has the discretion to
designate applicable RAS as limited impact, on a case-by-case basis. The drafting team asserts an entity’s compliance obligations
regarding a limited impact RAS are clear and unambiguous. For each RAS designated by the RC as limited impact, the entity must be
compliant with each applicable requirement of PRC-012-2.
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The drafting team agrees that the term limited impact is not defined. The drafting team maintains that the general description and
explanatory language regarding the limited impact designation provides high-level guidance for the RC to consider during the RAS review.
WECC and NPCC were cited because those are the only two Regions that classified RAS based upon certain criteria. The System Protection
and Control Subcommittee-System Analysis and Modeling Subcommittee team also recognized these Regional classifications and made
similar albeit different recommendations. The drafting team considered the attributes of each of these Regional classifications in creating
the guidance for limited impact designation. The limited impact designation is applicable on a continent-wide basis via NERC Reliability
Standard PRC-012-2.
Oshani Pathirane on Behalf of Payam Farahbakhsh, Hydro One Networks, Inc. - 1, 3
Answer
No
Comment
Comment 1 - R4.1.5 - In TPL-001-4, loss of a single line due to a fault is “Single Contingency” (Category P1), but the failure of a breaker or
protection relay following that single contingency is recognized as “Multiple Contingency” (Category P4 and P5) and has a different
performance requirement compared to the initial P1 event. Similarly, the system performance following a RAS failure to operate after an
event should not be required to meet the exact same requirements as those for the original event.
Therefore, we suggest deleting 4.1.5 and instead revising 4.1.4 to say “Except for limited impact RAS, the possible inadvertent operation
of the RAS, resulting from any single RAS component malfunction, or a single component failure in the RAS, when the RAS is intended to
operate, satisfies all of the following:”
Comment 2 - R5.1 – The wording “participate” which is used in the R5.1 does not define accountability or a definite action. For
consistency, we suggest using verbiage similar to that used in PRC-004-4’s description of accountabilities in the case of owning Shared
Protection Systems.
Comment 3 - R5.1.3 & R5.1.4 are related to performance of RAS and its impact on BES system. This assessment is better suitable for the
PC or RC to conduct
Comment 4 – In R5.2, in case of a RAS being owned by more than one RAS-Entity, it is unclear which RAS-Entity is accountable to
communicate with the RC and maintain evidence. The requirement needs to clearly identify who is accountable for what, similarly to how
PRC-004-4 describes accountabilities in case of Shared Protection System.
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Comment 5 – Similar to R5, the wording “participate” used in R6 does not define accountability or a definite action. For consistency, we
suggest using verbiage similar to that used in PRC-004-4’s description of accountabilities in the case of owning Shared Protection Systems.
Comment 6 - Similar to comment R5 above, R6 does not clearly define accountabilities in the case of a RAS being owned by more than
one RAS-Entity. In such case, which Entity is accountable to communicate with the RC and maintain evidences?
Comment 7 – It is unclear from the wording whether the RAS-entity would “Participate in analyzing the RAS operational performance”
with the RC, or only mutually agree upon a schedule for such activity with the RC.
Comment 8 - R8 is vague and subject to interpretation. There are references in the supplemental material that suggest maintenance
checking all of the logic in a PLC on a periodic basis is required and yet in PRC-005, it’s clear that there is no need to perform periodic
maintenance on relay logic. For monitored components, such as microprocessor relays, the “verification of settings [as] specified” in PRC005 (i.e., performing a settings compare) should be sufficient rather than implying that all logic needs to be re-verified. For RAS not
designated as limited-impact, R8 does not distinguish between monitored and unmonitored components of the RAS such as in PRC-005,
which would allow a RAS-entity to have a 12-year maintenance interval for monitored components.
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Response
Thank you for your comments.
COMMENT 1: The drafting team is not persuaded by the reasoning/example provided by the commenter to advocate that System
performance after a RAS failure to operate should be different (i.e. less stringent) than the System performance requirement for the
original contingency event for which the RAS is intended to operate. The drafting team asserts that the RAS failure to operate event
cannot be considered analogous to the breaker or protective relay failure to operate events (i.e. P4 and P5 contingencies) in Table 1 of
TPL-001-4. This is because implementing/installing a RAS is essentially the mitigation identified in the Corrective Action Plan required by
TPL-001-4 to demonstrate meeting the System performance for planning events. Please note that several examples of corrective actions
listed in TPL-001-4, Requirement 2, Part 2.7.1 are fully aligned with the RAS definition.
2.7.1. List System deficiencies and the associated actions needed to achieve required System performance. Examples of such actions
include:
• Installation, modification, or removal of Protection Systems or Special Protection Systems
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• Installation or modification of automatic generation tripping as a response to a single or multiple Contingency to mitigate
Stability performance violations.
• Installation or modification of manual and automatic generation runback/tripping as a response to a single or multiple
Contingency to mitigate steady state performance violations.
Allowing less stringent system performance for failure of RAS (except for limited impact RAS) to operate due to single component failure
would essentially be equivalent to rendering the RAS an inadequate mitigation for the very same System performance deficiencies
identified in TPL-001-4 that triggered the RAS implementation. Therefore, the System performance due to a RAS failure to operate must
be the same as for the original contingency event for which it was designed, and it may be a higher System performance bar than is
allowed for inadvertent RAS operation for certain contingency events. Consequently, the drafting team declines to merge Requirement
R4, Parts 4.1.4 and 4.1.5.
COMMENTS 2, 5, and 6: The drafting team is charged with assigning the requirements of the new standard to the specific users, owners,
and operators of the Bulk‐Power System while incorporating the reliability objectives of all the RAS‐related standards. In drafting this
standard, the drafting team has worked diligently to minimize the changes that will be required from the existing processes. The drafting
team recognizes that RAS with multiple owners inherently require coordination among all the participating RAS‐entities from the first
conceptual design through construction to operations, testing, maintenance and retirement. For purposes of PRC‐012‐2, when a RAS has
more than one owner, each RAS‐entity is obligated to participate in the various activities identified by the requirements to the extent of
its ownership. Collaboration, coordination, and communication between and among entities regarding RAS issues helps to ensure efforts
are not duplicated and best serves reliability by promoting awareness. For purposes of creating efficiencies, the drafting team maintains
registered entities that currently share ownership of a RAS (RAS‐entities) are in some manner already communicating, sharing
information, and coordinating RAS tasks such as operations analysis, Corrective Action Plan (CAP) development, and functional testing.
The drafting team is confident that entities will continue to do this after this standard is effective and that entities will communicate with
each other if there is any question or doubt of responsibility surrounding any requirement. From the NERC Drafting Team Reference
Manual, Version 2, January 2014, Attachment A — Verbs Used in Reliability Standards: “When developing a new or revised standard, DTs
should try to use terms that have already been defined or terms that are already used in other Reliability Standards to achieve a high
degree of consistency between standards. To that end, the Standards staff, working with key DT members, put together the following list
of verbs and their associated definitions. These verbs are all used in requirements in existing Reliability Standards. This verb list and its
definitions are not in the Glossary of Terms used in NERC Reliability Standards but these verbs and their definitions should serve as a
reference for DTs who are trying to minimize the introduction of new terms into Reliability Standards. Participate is defined as “To take
part or share in something.”
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COMMENT 3: The RAS-entity(ies) may need to collaborate with its associated Transmission Planner to comprehensively analyze RAS
operational performance. This is because a RAS operational performance analysis involves verifying that the RAS operation was triggered
correctly (Part 5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and 5.1.4) was consistent with
the intended functionality and design of the RAS. However, similar to the responsibility assigned to the RAS-entity and the possible
collaboration with the TP in R1, the drafting team contends that the RAS-entity is the suitable entity responsible for compliance to R5.
COMMENT 4: The term RAS‐entity is defined in the Applicability as the Transmission Owner, Generator Owner, or Distribution Provider
that owns all or part of a RAS. If all of the RAS (RAS components) has a single owner, then that RAS-entity has sole responsibility for all the
activities assigned within the standard to the RAS-entity.
The standard does not stipulate compliance methods. RAS-entities have the option of collaborating to fulfill their responsibilities for each
applicable requirement. Such collaboration and coordination should promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS-entity must be able to demonstrate its participation for compliance. As an example, the
individual RAS-entities could collaborate to produce and submit a single, coordinated Attachment 1 (acknowledging all RAS-entities that
participated in the provision of data) to the reviewing RC pursuant to Requirement R1 to initiate the RAS review process.
COMMENT 7: The drafting team contends that the wording of Requirement R5 clearly states that each RAS-entity shall participate in the
analyses of its RAS operations (with other RAS-entities, not the RC). The RAS-entity must perform the analyses and provide it to its RC
only if deficiencies in the RAS are found.
COMMENT 8: The reliability objective of Requirement R8 is to maintain the non‐Protection System components of a RAS; i.e., the
controllers (programmable logic controllers (PLCs), personal computers (PCs), multi‐function programmable relays, remote terminal units
(RTUs), and logic processors), and to verify the overall performance of the RAS through functional testing. Functional tests validate RAS
operation by ensuring System states are detected and processed, and that actions taken by the controls are correct and occur within the
expected time using the in‐service settings and logic (functional testing by default operates the processing logic and infrastructure of a
RAS). Functional testing should not be confused with the component focused maintenance of PRC‐005 Protection System Maintenance.
PRC‐005 is not applicable to non‐Protection System components such as RAS controllers. RAS designated as limited impact have
functional testing intervals of up to twelve full calendar years. However, all other RAS have up to six full calendar year intervals because
of the higher risk they pose to negatively impact BES reliability should they operate incorrectly or fail to operate. The drafting team
recognizes that PRC‐005 extends the maintenance interval for monitored multifunction programmable relays to twelve calendar years;
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however, the drafting team asserts that the inadvertent operation or failure of a RAS subject to the six year functional test interval poses
too much risk to the reliability of the BES to extend the test interval beyond six years.
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Comment
Regarding R4:
BPA believes that limited impact RAS should not be singled out to be exempt from meeting the performance requirements.
While the level of review could be lower, BPA believes a “limited impact” RAS should still be designed such that failure or inadvertent
operation of the RAS does not have an adverse impact on an adjacent TP or PC beyond the performance criteria for which the system is
planned.
Additionally, regarding R2:
BPA maintains that allowing an RC up to four months to complete the RAS review is longer than necessary and not in line with current
practice, which requires the information to be submitted to the RAS Reliability Subcommittee two weeks prior to the meeting where it
will be reviewed and approved or disapproved. Allowing four months could delay energization of new or functionally modified RAS by 14
weeks.
BPA also remains concerned by the term “mutually agreeable” and how it will be applied.
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The drafting team included the limited impact recognition in the standard to capture the intent of the RAS classification as suggested in
the SPCS-SAMS report. The limited impact designation is intended to recognize that RAS vary in complexity and impact on the BES. All
RAS (limited impact and others) must be considered in TPL assessments. In no instance does the limited impact designation exempt a RAS
from satisfying TPL-001-4 performance requirements.
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The drafting team asserts that the RC will take such impacts into account in its determination of limited impact status. Any RAS that
causes adverse impacts on adjacent systems beyond the performance criteria for which the RAS is planned strongly implies a scheme
exhibiting more than limited impact.
The time frame of four full calendar months is consistent with current utility and regional practices. The drafting team wrote the
requirement to allow for time intervals longer or shorter than four full calendar months by including the phrase "mutually agreed upon
schedule" among the affected parties. All RCs are required to have situational awareness of and responsibility for operational issues
adversely affecting BES reliability. Both awareness and responsibility provide an incentive to pre-empt and/or mitigate such operational
issues and any related operation limits when possible. When a RAS-entity’s Attachment 1 filing identifies such near-term operational
issues and demonstrates how the proposed RAS implementation would address them, it is difficult to believe that the RC would choose
to wait another 14 weeks to complete the RAS review when it is clear that delaying the RAS implementation would adversely impact the
BES reliability or capability.
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
No
Comment
As a general comment, HQT is in the view that PRC-012-2 should not address the details of how RAS entities should perform their analysis
according to requirement R8. Each RAS entity has systems operation applicability adapted to their particular topology and some systems
cannot withstand invasive actions (maintenance and testing activities) because of such topology. Therefore, PRC-012-2 requirements
should allow a certain level of flexibility to this effect, which HQT has commented further below.
Regarding comments specific to the wording of PRC-012-2 requirements, Footnote 2 in Attachment 1 is a definition, and it should be
treated as such. Also, the fourth bullet under footnote 2 reads “Changes to RAS logic beyond correcting existing errors” needs
clarification. What are the existing errors? The RAS should not have been approved if there were errors, and if it was approved with the
errors then those errors might be preventing the RAS from meeting its intended functionality. Suggest removing this bullet, and revising
the second bullet to read: Changes to the logic that affects the actions the RAS is designed to initiate. The preceding is also applicable to
Footnote 4 on page 25 for Attachment 2. Footnote 3 on page 23, footnote 5 on page 25, and footnote 6 on page 27 are not needed
because of the first comment above regarding Requirement R4.
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In addition, on page 27 in the Supplemental Material section, shouldn’t the Planning Coordinator, because of its wide-area view be
included in determining if a RAS can be designated limited impact?
In the two paragraphs preceding Requirement R1 on page 29 of the Supplemental Material section it should be emphasized that the
actions of the limited-impact RAS do not lead to the more severe BES consequences that would preclude a RAS from being defined a
limited-impact RAS. On page 34, same comment as in the preceding paragraph concerning “Changes to RAS logic beyond correcting
existing errors”. On page 34 of the Supplemental Material section in the third paragraph under Requirement R4, shouldn’t the Planning
Coordinator, because of its wide-area view, be involved in the designation of a RAS as limited-impact?
Also, on page 45 for the Technical Justifications for Attachment 1 Content Supporting documentation for RAS Review, comments
pertaining to footnote 8 the same as above for the comments regarding footnote 2.
HQT also has specific comments on requirements R5 and R8 as follows.
Firstly for NPCC, the Type ‘3’ should be written ‘III’. Also, VSL of R5 requests to ‘perform’ analysis. R5 mentioned only to ‘participate’. In
the Rationale section, at R4: references to Parts 4.1.3.1-4.1.3.5 should be corrected to 4.1.4.1-4.1.5. HQT is in the opinion that Lower VSL
of R7 should be High VSL because RC must be notified if CAP has changed since changes in action or timetables may require the RC to
intervene to maintain reliability.
Secondly, HQT suggests to remove footnote 3 on page 23, footnote 5 on page 25, and footnote 6 on page 27 by modifying the
Applicability section 4.2.1 in section 4.2 entitled Facilities by the following: ‘‘Remedial Action Schemes (RAS) not designated as “limited
impact”. A RAS designated as “limited impact” cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations.’’
Thirdly, regarding requirement R8, as mentioned in HQT’s general comments above, as for protection systems, invasive actions
(maintenance and testing activities) may introduce a higher number of misoperations which can stress the electrical system. As
recognized in PRC-005, new technology may offer the benefits to avoid this type of activities. Thus, from a reliability perspective, a RAS
Entity should decide which technique is most appropriate to verify the RAS integrity according to the complexity of their design. If for
some reason, a RAS entity would prefer to dynamically extract and compare the settings file of the RAS components instead of doing
functional tests, it could be another acceptable method to meet the intent of requirement of R8 without doing invasive actions that could
adversely affect the reliability of the system.
HQT notes that there is actually no difference made in PRC 005 for limited impact RAS components. However, HQT agrees with PRC 012-2
regarding the fact that limited impact RAS represents a low reliability risk to the BULK power system. For those RAS, HQT agrees that less
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stringent criteria can be applied. In PRC-005, there is no mention of limited impact RAS components, this concept should be incorporated
within the standard.
Finally, in light of the above comments, HQT is of the view that the maximum allowable interval between functional tests should be
twelve full calendar years for RAS that are not designated as limited impact RAS.
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Response
Thank you for your comments.
PRC-012-2 Requirement R8 requires the periodic completion of functional tests to verify the overall performance of the RAS but is not
prescriptive regarding the methods used to perform the tests. As described in the Rationale box and Supplemental Material section of the
standard for Requirement R8, entities have the flexibility to utilize end-to-end or overlapping segment testing.
Regarding the wording of footnote 2 and the term “functionally modified,” it is intended to be a list of examples of RAS modifications to
provide guidance to responsible entities. An example of an existing error is a previously undetected logic error made during
implementation of the RAS. The drafting team declines to make the suggested change.
The Planning Coordinator (PC) or Transmission Planner (TP) is the entity that performs the planning studies and most often identifies the
need for a RAS and/or determines the necessary RAS characteristics, including the proposal and justification for limited impact
designation. These studies are included in the Attachment 1 information supplied by the RAS‐entity to the Reliability Coordinator (RC) for
RAS review and approval. Because the PC is involved in developing the studies and/or evaluations, the drafting team did not include them
as mandatory participants in the RAS review and approval process where they would be responsible for judging and approving their own
work. Moreover, the drafting team contends that the limited impact description within the standard is sufficient to address the case
where the RAS actions lead to severe BES consequences.
The drafting team is satisfied with the language pertaining to limited impact RAS and its location in the footnote. The drafting team sees
no benefit by including limited impact RAS in the Applicability/Facilities section of the standard and declines to make the suggested
change.
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The drafting team corrected the references to NPCC Type III.
The drafting team declines to make the suggested change in the VSLs for Requirement R5. The use of “performed” is correct,
“participate” is incorporated by the phrase “in accordance with Requirement R5.”
The drafting team corrected the reference to the Parts (4.1.4.1-4.1.4.5) in the Rationale for Requirement R4.
The drafting team disagrees with the suggested change to the VSL for Requirement R7. Failing to update the CAP or not notifying the RC
following a CAP update or completion does not meet the criteria established for a Severe VSL.
The drafting team agrees that PRC-005 does not make a distinction for components related to limited impact RAS. The limited impact
recognition is referenced only in PRC-012-2.
The reliability objective of Requirement R8 is to maintain the non‐Protection System components of a RAS; i.e., the controllers
(programmable logic controllers (PLCs), personal computers (PCs), multi‐function programmable relays, remote terminal units (RTUs),
and logic processors), and to verify the overall performance of the RAS through functional testing. Functional tests validate RAS operation
by ensuring System states are detected and processed, and that actions taken by the controls are correct and occur within the expected
time using the in‐service settings and logic (functional testing by default operates the processing logic and infrastructure of a RAS).
Functional testing should not be confused with the component focused maintenance of PRC‐005 Protection System Maintenance. PRC‐
005 is not applicable to non‐Protection System components such as RAS controllers. RAS designated as limited impact have functional
testing intervals of up to twelve full calendar years. However, all other RAS have up to six full calendar year intervals because of the
higher risk they pose to negatively impact BES reliability should they operate incorrectly or fail to operate. The drafting team recognizes
that PRC‐005 extends the maintenance interval for monitored multifunction programmable relays to twelve calendar years; however, the
drafting team asserts that the inadvertent operation or failure of a RAS subject to the six year functional test interval poses too much risk
to the reliability of the BES to extend the test interval beyond six years. The drafting team declines to make the suggested change to the
functional testing interval.
Larry Heckert on Behalf of Kenneth Goldsmith, Alliant Energy Corporation Services, Inc. - 4
Answer
Yes
Comment
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Alliant Energy supports comments submitted by the MRO NERC Standards Review Forum.
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Response
Thank you for your comments.
Please see the drafting team’s responses to the referenced comments.
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer
Yes
Comment
In the Supplemental Material, on p. 30 of 55 of the redlined document, please clarify what is meant by “…affected by the
contingency.” Specifically, is this the contingency that would require RAS operation, or is the contingency the overloading of the BES
Element?
Outside of the scope of the survey question -- in Measurement M5, please consider changing “…with participating RAS-entities and…” to
“…with participating RAS-entities, if applicable, and…”
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Thank you for your comments.
This is the Contingency which results in an overload that the RAS is intended to mitigate.
The drafting team does not see any additional benefit from your suggested change. No change made to the standard.
David Greene - SERC Reliability Corporation - 10, Group Name SERC DRS
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Answer
Yes
Comment
SERC DRS suggests a revision as to what constitutes a limited impact RAS. Currently, the language in the standard suggests that an RAS
considered to be limited impact cannot:
“cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or
unacceptably damped oscillations”
We suggest revising the above language by inserting the term “widespread” before angular instability. Angular instability could be
experienced by just one generating unit going out of sync. A single generating unit becoming unstable is not indicative of an unstable or
unreliable BES, and we do not believe that this should remove an RAS from limited impact consideration.
The comments expressed herein represent a consensus of the views of the above-named members of the SERC EC Dynamics Review
Subcommittee only and should not be construed as the position of SERC Reliability Corporation, its board, or its officers.
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Thank you for your comments.
The drafting team avoids the use of adjectives such as “widespread” because of the ambiguity those terms introduce. The drafting team
maintains that the “BES” qualifier in the statement regarding the limited impact designation modifies all of the conditions that follow; i.e.,
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, and unacceptably damped oscillations. As you
suggest, the instability of a single generating unit or small generating plant would not be indicative of an unstable or unreliable BES;
however, the RC is the final arbiter for determining whether the RAS qualifies for limited impact status based upon review of the
Attachment 1 information.
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Answer
Yes
Comment
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However, the NSRF proposes including the following opinion in the Supplemental Material section:
R4 – This requirement refers to ‘single component malfunction’ and ‘single component failure’. However, the standard does not contain
any qualification of which types of components must be included in RAS evaluations or what entity ultimately makes the component
inclusion determination. Therefore, to avoid making elaborate component inclusion qualifications or letting there be uncertainty over
which entity makes the final component inclusion determination, add text to the Supplemental Material section such as, “The RC will
make the final determination regarding which RAS components are included in the RAS evaluation during its review”.
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The drafting team included language as you suggested in the Supplemental Material section of the draft standard for Requirement R1. It
is not the intent of Requirement R4 that the PC performing the evaluation examine the physical implementation of the RAS, but rather to
assess the System impacts of a failure to operate or an inadvertent operation. If redundant components were used to implement the RAS
such that a single component failure would not prevent the RAS from operating, this would be confirmed by the RC during the initial
review and then verified by subsequent functional testing, and should not need to be re-examined during the periodic evaluation per
Requirement R4. However, if the RAS is designed to meet the “failure to operate” or “inadvertent operation” objectives by over-arming
of load or alternate actions, the continued effectiveness of these alternative actions should be evaluated.
William Temple on Behalf of Mark Holman, PJM Interconnection, L.L.C. - 2
Answer
Yes
Comment
PJM supports the comments submitted by the ISO/RTO Council.
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Public Service Enterprise Group , 1,3,5,6, Koncz Christy
Response
Thank you for your comment.
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Please see the drafting team’s responses to the referenced comments.
John Pearson on Behalf of Michael Puscas, ISO New England, Inc. - 2
Answer
Yes
Comment
Requirement R4.1.3 includes language from the associated footnote verbatim. The language in the footnote should be deleted. The
requirement also seems to define a limited impact RAS. The NERC Glossary should include the definition of a limited impact RAS.
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Response
Thank you for your comments.
The drafting team disagrees that the footnote should be deleted and that Requirement R4, Part 4.1.3 is redundant with the footnote. The
drafting team has determined that the general description of limited impact RAS, which only describes actions to which a RAS cannot
cause or contribute and be considered limited impact, does not rise to the level of a definition that should be included in the Glossary of
Terms Used in NERC Reliability Standards. Rather, the explanation of a limited impact RAS is only high level guidance that must be
considered by an RC when using its discretion and its wide area perspective to determine whether a limited impact designation is
appropriate for a given RAS.
Erika Doot - U.S. Bureau of Reclamation - 5
Answer
Yes
Comment
The Bureau of Reclamation agrees with the changes proposed by the drafting team.
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Response
Thank you for your support.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC No HQ and Dominion
Answer
Yes
Comment
Footnote 1 in Requirement R4 is not needed as written. It just reiterates the wording of sub 4.1.3. Same applies to footnote 9 on page
46 as the wording in sub 4.1.3 pertains to the entire document. An appropriate footnote would read that NPCC Type 3 classification and
the WECC LAPS classifications will be recognized as limited-impact RAS.
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Response
Thank you for your comments.
The drafting team disagrees that the footnote should be deleted and that Requirement R4, Part 4.1.3 is redundant with the footnote. The
drafting team has determined that the general description of limited impact RAS, which only describes actions to which a RAS cannot
cause or contribute and be considered limited impact, does not rise to the level of a definition that should be included in the Glossary of
Terms Used in NERC Reliability Standards. Rather, the explanation of a limited impact RAS is only high level guidance that must be
considered by an RC when using its discretion and its wide area perspective to determine whether a limited impact designation is
appropriate for a given RAS. The drafting team declines to make the suggested change to the footnote.
John Fontenot - Bryan Texas Utilities - 1
Answer
Yes
Comment
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Response
Michael DeLoach - AEP - 3
Answer
Yes
Comment
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Response
Michael DeLoach - AEP - 3
Answer
Yes
Comment
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Response
Randi Heise - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion - RCS
Answer
Yes
Comment
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Response
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC-ISONE
Answer
Yes
Comment
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Response
Mike Smith - Manitoba Hydro - 1
Answer
Yes
Comment
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0
Response
Thomas Foltz - AEP - 5
Answer
Yes
Comment
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Response
Allie Gavin on Behalf of Michael Moltane, International Transmission Company Holdings Corporation - 1
Answer
Yes
Comment
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Response
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Comment
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0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Comment
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Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Comment
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Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3
Answer
Yes
Comment
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Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Comment
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Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Comment
Texas RE noticed the SDT did not specifically address its comments submitted on January 8, 2016. Texas RE respectfully requests the SDT
to respond to its comments.
As previously stated in comments submitted on January 8, 2016, Texas RE does not agree with the provision that a RAS can be designated
as “limited impact”. Texas RE recommends the SDT reconsider and treat all RASes, that affect the reliability of the Bulk Electric System
(BES) equally.
However, if the SDT elects to keep the limited impact designation, Texas RE is concerned the proposed criteria for determining a “limited
impact” RAS is vague and ambiguous (e.g. “… BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations). Absent clear criteria, the RC may designate certain RASes as limited impact that would be
more properly characterized as a RAS. Because limited impact RASes are subject to reduced reliability-related considerations by the
Reliability Coordinator (i.e. Attachment 2) and limited evaluation performed by the Planning Coordinator (i.e. Requirement 4), the
improper characterization of RASes may lead to potential reliability gaps on the BES.
Texas RE inquires as to what the SDT used as technical basis (such as industry reports, recommendations from task forces or working
groups, field studies, etc) in determining to create a requirement to designate limited impact RASes.
TPL-001-4
In Requirement R4.1.5, Texas RE is concerned the planning requirements in TPL-001-4 do not distinguish between limited impact RAS and
RAS. For example under TPL-001-4, a PC must consider an operation of a RAS, including a limited impact RAS, that results in an applicable
Facility Rating being exceeded. Texas RE understands planning and RAS evaluation are separate obligations for the PC with separate
requirements. However, the language in R4.1.5 specifically identifying the “same performance requirements” as defined in TPL-001-4
potentially blurs these two obligations with respect to limited impact RAS. Texas RE suggests eliminating the phrase “Except for limited
impact RAS” in R4.1.5 so PRC-012-2 and TPL-001-4 cannot be interpreted to potentially conflict with each other.
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Degraded RAS
Texas RE submitted comments on October 5, 2015 stating its concern there is no requirement to report the degraded RAS to the RC. The
SDT responded:
The status of a degraded RAS is required to be reported (in Real-time) to the Transmission Operator via PRC-001, Requirement R6, then
to the RC via TOP-001-3, Requirement R8. See Phase 2 of Project 2007-06 for the mapping document from PRC-001 to other standards
regarding notification of RC by TOP if a deficiency is found during testing. Consequently, it is not necessary to include a similar
requirement in this standard.
Texas RE does not agree this issue is handled in the standards identified by the SDT in its response. As an initial matter, TOP-001-3 R8
does not necessarily require the TOP to inform the RC. TOP-001-3 R8 is specifically limited to Emergencies, which do not necessarily
include degradation of a RAS. Does the SDT envision treating all RAS degradations as Emergencies as defined by the NERC Glossary of
Terms in order to trigger the TOP-001-3 R8 reporting obligations?
TOP-001-3 also uses the term “Transmission Operator Area” which, by definition, does not necessarily include DP and GO, which are
“RAS-entities”, equipment if used in a RAS. This is a gap in reliability.
In addition, other related standards do not appear to require RAS-entities to report degraded RASes to the RC in all circumstances. For
example, TOP-003-3 discusses having a data specification and distributing the data specification. However, this Standard does not
explicitly include notification of actual degradation of a RAS to an RC or explicitly require entities to provide actual data. In particular,
TOP-003-3 R3 states “Each Transmission Operator shall distribute its data specification to entities that have data required by the
Transmission Operator’s Operational Planning Analyses, Real-time RAS monitoring, and Real-time Assessment.” Moreover, TOP-003-3 R3
explicitly covers the “Operations Planning” Time Horizon (not Real-time or Same-Day Operations). TOP-003-3 R5 also states “Each
Transmission Operator, Balancing Authority, Generator Owner, Generator Operator, Load-Serving Entity, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R3 or R4 shall satisfy the obligations of the documented
specifications…”. Again, under this Standard, there is no explicit requirement that entities provide the RC that is reviewing and approving
the RAS the actual data regarding the “current Protection System and Special Protection System status or degradation that impacts
System reliability.”
Misoperations
The definition of Misoperation that becomes effective on July 1, 2016 does not include RASes. Texas RE recommends clarifying R5 by
defining misoperation to align with PRC-004-4. If misoperation is not defined, entities might not do the actions outlined in R 5.1. The
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SCPS drafted a RAS template to describe misoperations which were never officially approved. Texas RE recommends adding a definition
of misoperations for RASes in the Standard or NERC Glossary based on the SCPS RAS template and the language in R5.
Also, while reporting of Protection Systems Misoperations will be contained within the Section 1600 Data Request for PRC-004, neither
PRC-012-2 nor the Section 1600 data request provides a corresponding reporting requirement for RAS misoperations to the Regional
Entities or NERC. Texas RE recommends the SDT consider adding a requirement, either to PRC-012-2 or to the Section 1600 data request,
for Registered Entities to report misoperations of RASes to regional entities.
Functional Testing – R8
Texas RE is concerned PRC-012-2 R8 does not address the scenario where a RAS is owned by different companies. In particular, PRC-012-2
R8, as currently drafted, does not require simultaneous testing each separately-owned component of the RAS-system simultaneously so
that entities can verify that the RAS properly operates. For example, there are instances in Texas where a GO and TO own part of the
same RAS. Under the current Standard language, the GO will test the receipt signal and the TO will test sending signal. However, there is
no requirement for the GO and TO to coordinate the tests of their individual components to ensure that signal is sent and received. Put
differently, although each individual component may be tested, there is no corresponding test of to ensure the entire RAS will operate as
intended. Texas RE is concerned a reliability gap will occur if the two tests are not conducted simultaneously and in such a way the GO
and TO can view the results of the test on the entire RAS.
Full Calendar Months
The SDT introduces a new term “full calendar months” that is neither defined in the Standard nor the NERC Glossary and is inconsistent
with other Reliability Standards. Texas RE noticed a definition in the PRC-012-2 RSAW, but the definition should be in the NERC Glossary
or within PRC-012-2 itself instead. Texas RE recommends the SDT provide the definition within the Standards process while considering
other definitions already in place (such as “Calendar Year” in PRC-005-6).
Corrective Action Plan
As previously submitted on January 8, 2015, Texas RE recommends revising PRC-12-2 R7 to place at least minimal criteria around
modifications to Corrective Action Plans (CAP) or corresponding CAP timetables. As currently drafted, PRC-12-2 R7 could be interpreted
to permit RAS-entities to perpetually update their CAPs if “actions or timetables change” and then merely notify the RC of such
changes. Texas RE recommends that the SDT consider some minimal criteria that RAS-entities must satisfy in order to update a CAP
under PRC-12-2 R7.2. For instance, PRC-12-2 R7.2 could be revised to read: “Update the CAP for any reasonable changes in the required
actions or implementation timetable.” In turn, PRC-12-2 R7.3 could be revised to read: “Notify each reviewing Reliability Coordinator and
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provide a reasoned justification for changes in CAP actions or timetables, and notify each reviewing Reliability Coordinator when the CAP
is completed.”
Feedback Mechanism
Texas RE noticed there is no feedback mechanism in the current standard for PCs to incorporate RC approved RAS modifications in
subsequent planning processes. Texas RE understands this might not appropriate for the scope of this project, but requests the SDT to
consider this issue in future reviews of applicable standards.
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Thank you for your comments.
The drafting team disagrees with your premise that the limited impact designation creates a reliability gap. As the drafting team has
previously stated, we included the limited impact recognition in the standard to capture the intent of the RAS classification as suggested
in the SPCS-SAMS report. The limited impact designation is intended to recognize that RAS vary in complexity and impact on the BES. All
RAS (limited impact and others) must be considered in TPL assessments.
The drafting team developed the following to explain the relationship between TPL-001-4 and PRC-012-2.
1. All RAS (limited impact and non-limited impact) must be considered in TPL assessments. In no instance does the limited impact
designation exempt a RAS from satisfying TPL-001-4 requirements. As far as TPL assessments are concerned, all RAS are assumed
to operate correctly and the possible incorrect operation of RAS are not addressed by TPL-001-4. PRC-012-2 addresses this issue
as described in #3 below.
2. Adherence to the TPL performance requirements is presupposed by PRC-012-2. PRC-012-2 further assures RAS compliance to TPL
performance requirements (where applicable to planning events) by documenting the design and performance of the RAS
through Attachment 1, Section II, item 3. The RC will verify that RAS actions satisfy performance objectives for the scope of events
and conditions that the RAS is intended to mitigate according to the complementary portion of Attachment 2, Section I, item 1.
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3. PRC-012-2 requires RAS to meet design and implementation requirements in addition to any applicable TPL-001-4 performance
requirements. These design and implementation requirements pertain to inadvertent operation and failure to operate, and are
included in the information required by Attachment 1, Section II, item 6 and Section III, item 4. The complementary portion of
Attachment 2 used by the RC during the RAS review is Section I, items 5 and 7 and Section II, item 2.
4. RAS vary widely in their complexity and impact on the reliability of the BES. For RAS on the low end of the BES impact range, the
standard allows for exemptions on the design and implementation requirements that are more appropriate for high-impact RAS.
These exemptions are permitted only for these low impact (i.e., limited impact) RAS. As stated in the Supplemental Material
section of the draft standard, requiring RAS with minimal impact to the BES to satisfy the single component failure and single
component malfunction tests would add complexity to the RAS design and implementation with minimal benefit to BES reliability.
5. The RAS-entity provides justification for any RAS proposed as limited impact via Attachment 1, Section II, item 5. The RC will use
the complementary portion of Attachment 2, Section I, item 6 to verify the RAS qualifies for limited impact designation.
6. The RC is responsible for reviewing all of the Attachment 1 information, including studies regarding any proposed new or
functionally modified RAS. The RC is the functional entity best suited to perform the RAS review and make the limited impact
designation because it has the widest area operational and reliability perspective of all functional entities and an awareness of
reliability issues in any neighboring RC Area. A RAS designated by the RC as limited impact cannot, by inadvertent operation or
failure to operate, cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations. If the RAS is not deemed to be limited impact, then the additional documentation
associated with a RAS single component malfunction (Attachment 1, Section II, item 6) and a RAS single component failure
(Attachment 1, Section III, item 4) is required.
7. PRC-012-2, Requirement R4 mandates that all RAS will be periodically evaluated to verify the continued effectiveness and
coordination of the RAS, as well as to verify that, if a RAS single component malfunction or single component failure were to
occur, the requirements for BES performance would continue to be satisfied. A periodic evaluation is required because changes in
system topology or operating conditions may change the effectiveness of a RAS or the way it impacts the BES. Requirement R4,
Part 4.1.3 requires that limited impact RAS be evaluated for the inadvertent operation of the RAS or the failure of the RAS to
operate to ensure that the RAS still warrants the limited impact designation. If the RAS is not deemed to be limited impact, then
the additional evaluations associated with RAS single component malfunction (Requirement R4, Part 4.1.4) and a RAS single
component failure (Requirement R4, Part 4.1.5) are required.
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TPL-001-4: It is correct to state that TPL-001-4 does not distinguish between limited impact and other RAS. The actions of both types of
RAS must be taken into account in the evaluation of Contingency events on the System in the System assessment required by TPL-001-4.
The System performance requirements in TPL-001-4 must be met considering the actions of both types of RAS. The intent of Requirement
R4, Part 4.1.5 is to verify that a single component failure in a RAS, other than limited impact RAS, when the RAS is intended to operate,
does not prevent the BES from meeting the same performance requirements (defined in Reliability Standard TPL-001-4 or its successor)
as those required for the events and conditions for which the RAS is designed. This analysis is needed to ensure that changing System
conditions do not result in the single component failure requirement not being met. Requirement R4, Part 4.1.5 exempts the PC from
evaluating limited impact RAS with regards to single component failure. The drafting team declines to make the suggested change.
Degraded RAS: The drafting team reiterates that the RC will be notified of degraded RAS. Please see the Mapping Document for Project
2007-06.2 Phase 2 of System Protection Coordination for Requirement R6 of PRC-001-1.1(ii) which logically maps out how the reliability
objective of Requirement R6 is accomplished by requirements in other Reliability Standards.
Misoperations: The drafting team agrees that the definition of Misoperations for Protection Systems does not and should not include
references to RAS because RAS are not Protection Systems. The drafting team constructed Requirement R5 such that all RAS operations,
partial operations, and failure of RAS to operate when expected must be analyzed. The drafting team contends that Requirement R5 is
clear and unambiguous as-written without a formal definition of a RAS misoperation being developed. NERC and the Regional Entities can
request information at any time using a Section 1600 Data Request, so the addition of another requirement in PRC-012-2 is not
necessary.
Functional Testing – R8: The standard requirements do not specify compliance methods, only the reliability objective(s). Requirement R8
mandates the overall RAS performance be verified, not that an overall test be conducted. Functional testing may be accomplished with
end-to-end testing or a segmented approach. For segmented testing, each segment of a RAS must be tested. Overlapping segments can
be tested individually negating the need for complex maintenance schedules and outages. When a RAS has more than one owner, each
RAS‐entity is obligated to participate in the various activities identified by the requirements to the extent of its ownership. Collaboration,
coordination, and communication between and among entities regarding RAS issues helps to ensure efforts are not duplicated and best
serves reliability by promoting awareness. For purposes of creating efficiencies, the drafting team maintains registered entities that
currently share ownership of a RAS (RAS‐entities) are in some manner already communicating, sharing information, and coordinating RAS
tasks such as operations analysis, Corrective Action Plan (CAP) development, and functional testing. The drafting team is confident that
entities will continue to do this after this standard is effective and that entities will communicate with each other if there is any question
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63
or doubt of responsibility surrounding any requirement. Because Requirement R8 mandates that RAS-entities verify the overall RAS
performance and the proper operation of non-Protection System components, overlapping segment testing is required if segment testing
is utilized rather than end-to-end testing. Your example appears to neglect the use of overlapping segment testing.
Full Calendar Months: The drafting team does not consider “full” to be a definitional term, rather a clarifying term used with a time
interval. The drafting team uses the clarifier ‘full’ to be clear that partial time increments are not counted. For example, for four calendar
months, if the starting point is in the middle of a calendar month (October 15), four full calendar months would begin November 1 and
continue through February 28 (the last day of the month of the stated period).
Corrective Action Plan: As discussed in the Rational for Requirement R6 and R7, the implementation of a properly developed CAP ensures
that RAS deficiencies are mitigated in a timely manner. The A RAS deficiency may require the RC to impose operating restrictions so the
System can operate in a reliable way until the CAP is completed. The drafting team contends that the probable operating restrictions will
incent the RAS-entity to complete the CAP as quickly as possible. It is conceivable that an entity may have a “reasoned” justification to
defer the end of a CAP; but as the drafting team just stated, there should be no reliability implications associated with the delay.
Feedback Mechanism: RAS modifications approved by the RC should be captured in subsequent PC planning processes in the same way
as any other future planned reinforcement projects. The owner of the RAS would be expected to provide applicable steady-state,
dynamic, and short circuit modeling data to its TP and PC according to the data requirements and reporting procedures developed per
MOD-032-1, and a PC would incorporate this information into its planning models per TPL-001-4 Requirement R1, Part 1.1.3.
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2. Implementation Plan for PRC-012-2: The drafting team revised the Implementation Plan to provide for the initial consideration of
limited impact RAS, and to clarify that the initial obligation under Requirement R9 for a Reliability Coordinator that does not have a
RAS database is to establish a RAS database by the effective date of PRC-012-2. Do you agree with the revised Implementation Plan? If
no, please provide the basis for your disagreement and an alternate proposal.
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
No
Comment
In light of the above comments, HQT is of the view that the maximum allowable interval between functional tests should be twelve full
calendar years for RAS that are not designated as limited impact RAS.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The reliability objective of Requirement R8 is to maintain the non‐Protection System components of a RAS; i.e., the controllers
(programmable logic controllers (PLCs), personal computers (PCs), multi‐function programmable relays, remote terminal units
(RTUs), and logic processors), and to verify the overall performance of the RAS through functional testing. Functional tests validate
RAS operation by ensuring System states are detected and processed, and that actions taken by the controls are correct and occur within
the expected time using the in‐service settings and logic (functional testing by default operates the processing logic and infrastructure of
a RAS). Functional testing should not be confused with the component focused maintenance of PRC‐005 Protection System Maintenance.
PRC‐005 is not applicable to non‐Protection System components such as RAS controllers. RAS designated as limited impact have
functional testing intervals of up to twelve full calendar years. However, all other RAS have up to six full calendar year intervals because
of the higher risk they pose to negatively impact BES reliability should they operate incorrectly or fail to operate. The drafting team
recognizes that PRC‐005 extends the maintenance interval for monitored multifunction programmable relays to twelve calendar years;
however, the drafting team asserts that the inadvertent operation or failure of a RAS subject to the six year functional test interval poses
too much risk to the reliability of the BES to extend the test interval beyond six years.
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65
Douglas Webb on Behalf of Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co. - 3, 6, 5, 1
Answer
No
Comment
In consideration of our comments relating to the term “limited impact,” we are unable to support the Implementation Plan. The
alternative proposal is incorporate into the Implementation Plan a future defined NERC Glossary term for “limited impact.”
Likes
0
Dislikes
0
Response
Thank you for your comments.
The drafting team maintains the description of limited impact is sufficient and declines to make the suggested change to the
Implementation Plan.
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
No
Comment
ERCOT signs on to the IRC SRC comments for Question 2. The SRC comments are as follows:
The rationale for R2 states that RC review “minimizes the possibility of a conflict of interest that could exist because of business
relationships among ….” This explanatory purpose for R2 is not needed and in fact could prove untrue as not all RCs are independent
from TOs, GOs, etc.
The R3 rationale inserts the idea of “lack of dependability”. This can be understood differently by different parties. For a hardware
supplier, it can mean the equipment or technology is unreliable. And if taken to an extreme, this seems to open the path to requiring the
RC to decide which generators should run based on the individual generators’ forced outage rate (dependability rate?). We suggest this
phrase be stricken from the R3 explanatory.
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For R4 the limited impact designation explanation, please clarify whether the reference to regions is meant to be an example of how the
SDT came to its decision for R4 or whether it is a reference of the authority of what regions can do. We believe it is the former and the
language should be improved.
The concept of 4.1.2 to “avoid adverse interactions” would seem to need some criteria for evaluating what “avoid” means. Rather than
state “avoid”, we suggest this requirement to be rewritten to state: “The RAS does not adversely impact the performance of other RAS,
and protection and control systems.”
·
4.1.4.4. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency voltage deviation limits as established by
the Transmission Planner and the Planning Coordinator. Some Planners don’t use voltage deviation criteria. This should it not be
rewritten to state “BES voltages shall be within the Planning Coordinator’s voltage criteria under pre and post contingency conditions”.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The Rationale for Requirement R2 states that the RC review “minimizes” the possibility of a conflict of interest; it does not say that it
“eliminates” the possibility. The drafting team maintains that the RC is the functional entity best suited to perform the RAS review
because it has the widest area perspective of all functional entities and minimizes the possibility of a conflict of interest that could exist
because of business relationships among the RAS‐entity, Planning Coordinator (PC), Transmission Planner (TP), or other entities that are
likely to be involved in the planning or implementation of a RAS.
The phrase “lack of dependability” in the Rationale for Requirement R3 is an example of one of the possible reliability issues with the RAS
that the RC review is intended to discover.
WECC and NPCC were cited because those are the only two Regions that classified RAS based upon certain criteria. The SPCS-SAMS team
also recognized these Regional classifications and made similar albeit different recommendations. The drafting team considered the
attributes of each of these regional classifications in creating the guidance for limited impact designation. The limited impact designation
is applicable on a continent-wide basis via NERC Reliability Standard PRC-012-2. Based on your comment, the drafting team modified the
language in the Rationale box.
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The drafting team maintains that the current language “avoids adverse interactions” is clear and that the suggested language does not
provide additional clarity.
Requirement R5 of TPL-001-4 requires PC’s and TP’s to have criteria for post contingency voltage deviations.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
No
Comment
Implementation Plan
Texas RE recommends reducing the implementation period. This is a series of processes that already exist in some form or fashion and
should not require a new construct that would take three years. In Requirement R9, the SDT indicates requirements follow “industry
practice” which is a twelve month periodicity. Does the SDT contend that there are RASes in place that an RC or PC does not know
about?
Texas RE recommends that the SDT eliminate the proposed implementation period or at least shorten the proposed three-year
implementation period for PRC-12-2 to six months. Alternatively, the SDT should link the 60-full-calendar month (currently revised to “5
full calendar years”) compliance window in PRC-12-2, R4 and the six- and twelve-year compliance periods in PRC-12-2, R8 to the effective
date of PRC-12-2 and not the extended date (if any) set forth in the proposed implementation plan.
The proposed PRC-12-2 establishes a process for reviewing new, functionally modified, or retiring RAS. As the SDT has recognized, failing
to implement such a RAS review process could result in a significant gap in reliability. Specifically, the SDT stated in the rationale for
Requirement R1 that RAS “action(s) can have a significant impact on the reliability and integrity of the Bulk Electric System (BES).” Given
the importance of the RAS review scheme for reliability, Texas RE believes that three years is too long to implement the process
contemplated in the proposed PRC-12-2.
Review Process Timeline
Texas RE also believes that the nature of the review process itself also counsels in favor of a shorter review period. For example, PRC-122, R1 – R3 establishes the basic framework for RAS review. These requirements mandate that RAS-entities provide certain information
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regarding RAS to their respective Reliability Coordinators (RC), a minimum four full calendar month period for the RC to review this
information, and then a subsequent obligation for the RAS-entity to resolve any reliability issues identified by the RC prior to installing,
functionally modifying, or retiring a particular RAS. Accordingly, these requirements do not contemplate immediate changes to existing
physical assets, significant internal process transformations, or other issues that could potentially justify a three-year implementation
period. Rather, they largely focus solely on the exchange and review of documentation, such as one-line drawings, for each RAS that is
likely already be in the RAS-entity’s possession today. RAS-entities and their associated RCs should therefore be able to begin the RAS
review process with only minimal lead time following the adoption of PRC-12-2. Texas RE would further note that although RCs may need
additional compliance resources to perform the RAS reviews contemplated under PRC-12-2, the existing language in PRC-12-2, R2 already
provides RCs and RAS-entities with the flexibility to extend the review period if necessary based on a “mutually agreed upon schedule.”
A similar rationale applies to the misoperation review and correction process in PRC-12-2, R5. As the SDT notes, “[t]he correct operation
of a RAS is important for maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS indicates that the RAS
effectiveness and/or coordination has been compromised.” Texas RE agrees with this statement. In light of this fact, however, Texas RE
believes that RAS-entities should begin RAS operational performance assessments following a RAS failure or misoperation immediately
upon adoption of PRC-12-2 in order to avoid a significant reliability gap.
If the SDT elects to retain an implementation period of any length, Texas RE recommends that such implementation plan not apply to
PRC-12-2, R4 and R8. These requirements already have significant time periods for RAS-entities to complete their compliance obligations
embedded within them. For example, RAS-entities have six years under PRC-12-2, R8 to complete initial functional tests of their RAS (and
12 years for limited impact RAS if that definition is retained). Given that PRC-12-2, R4 and R8 already provide extended compliance
horizons, Texas RE does not believe that additional time is necessary to implement these requirements. Instead, the 6-full-calendar
month period in PRC-12-2, R4 and the six- and twelve-year periods in PRC-12-2, R8 should begin on the effective date of PRC-12-2 itself.
Additionally, the Implementation Plan contains the same “limited impact” language Texas RE has concerns about.
Texas RE requests the SDT provide justification for the testing timelines.
Likes
0
Dislikes
0
Response
Thank you for your comments.
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69
Review Process Timeline
The notion that entities could use the “mutually agreed upon schedule” clause in the Standard assumes that all entities are already able
to meet all the requirements of the Standard. The drafting team is unable to make this assertion and expects that many functional
entities will need to establish new frameworks which could include the hiring and training of personnel to ensure the requirements of
Reliability Standard PRC-012-2 are met. The drafting team asserts that the 36 month implementation period is reasonable and
appropriate.
Entities are encouraged to begin work prior to the effective date of the Standard. For example, an entity may choose to work with their
RC prior to the effective date of the Standard to submit the information to determine that a RAS is limited impact prior to
implementation, but that designation does not become relevant until the effective date of PRC-012-2.
The existing NERC PRC-016-1 Remedial Action Scheme Misoperations will not be retired until the effective date 36 months after PRC-0122 is approved by the appropriate authority. Therefore, the drafting team contends that no reliability gap will exist.
The effective date of the Standard is the first day of the first calendar quarter that is thirty six (36) months after the effective date of the
applicable governmental authority’s order approving the standard. The drafting team declines to make the suggested change because the
drafting team feels that the implementation period, as drafted, provides a necessary period for preparation for compliance and because
this time period is consistent with the implementation period for the rest of the standard.
The Reliability Coordinator has responsibility for reliability of operations within its Reliability Coordinator Area and has discretion to
designate a RAS as limited impact on a case-by-case basis. The drafting team has determined that the general description of limited
impact RAS, which only describes actions to which a RAS cannot cause or contribute and be considered limited impact, does not rise to
the level of a NERC Glossary definition. Rather, the explanation of a limited impact RAS is only high level guidance that must be
considered by an RC when using its discretion and its wide area perspective to determine whether a limited impact designation is
necessary for a given RAS.
The drafting team reviewed PRC-005-6 and selected the functional testing interval in an attempt to build synergy between the two
Standards. The drafting team believes the same maintenance and testing groups will participate in the component testing of PRC-005-6
and the functional testing of PRC-012-2. The drafting team understands that PRC‐005-6 provides variable maintenance intervals to up to
twelve calendar years for multifunction programmable relays dependent on monitoring; however, the drafting team asserts that the
inadvertent operation or failure of a RAS subject to the six year functional test interval poses too much risk to the reliability of the BES to
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extend the test interval beyond six years (12 years for RAS determined to have a limited impact) regardless of the monitoring in place.
The drafting team attempted to balance the reliability interest of frequent functional testing with the resources required to perform that
testing, which can be significant, and believes that six years is a reasonable compromise.
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Comment
There was no general comment section provided this round, so TVA is providing the following comments to support our negative votes
on the ballot:
TVA continues to believe that the responsibility for reviewing and approving new or functionally modified RAS schemes belongs with the
Planning Coordinator and not the Reliability Coordinator. Oversight of the planning of the Bulk Electric System or the entities responsible
for Bulk Electric System planning belongs with the Planning Coordinator. From TVA’s perspective, the proposed standard, as written, is
in direct conflict with the Functional Model, and requires a compelling reason to justify the deviation. The facts that there are fewer
Reliability Coordinators (as opposed to Planning Coordinators) and that the Reliability Coordinators have the “widest-area view” do not
support a significant deviation from the Functional Model. Moreover, such analysis would beyond the normal Reliability Coordinator
functions, the Reliability Coordinators would not have the expertise to conduct RAS analysis in the planning horizon. Simply put,
Reliability Coordinators do not have trained personnel or the appropriate tools to complete a comprehensive assessment. Planning
Coordinators have oversight over all other aspects of planning of the Bulk Electric System, and there is no reason to treat Remedial Action
Schemes differently.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The drafting team acknowledges that the need for a RAS and/or the determination of RAS characteristics are most often identified
through planning studies performed by the Planning Coordinators or Transmission Planners. The NERC Functional Model is a guideline
for the development of standards and their applicability and does not have compliance requirements. The drafting team is not precluded
from developing Reliability Standards that address functions not described in the model. Reliability Standard requirements take
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precedence over the Functional Model. For reference, please see the Introduction section of NERC’s Reliability Functional Model, Version
5, November 2009.
The drafting team maintains that the Reliability Coordinator (RC) is the best‐suited functional entity to perform the RAS reviews because
the RC has the widest‐area reliability perspective of all functional entities and an awareness of reliability issues in neighboring RC Areas.
The RC is also more likely to be independent of the entities involved in planning and implementing the RAS. The drafting team does not,
by virtue of assigning the RAS review to the RC, expect the RC to possess more information or ability than anticipated by their functional
registration as designated by NERC.
As the drafting team stated in the Rationale and Supplemental Material section of the standard, the RC has the “flexibility” to request
information or assistance from relevant entities (third parties) to participate in the review if they believe it will enhance the quality and
efficiency of the review process. The ability of the RC to solicit assistance in performing the RAS review does not indicate that the RC is
not equipped to perform the RAS review, or that another party should be chosen to perform the review. To the contrary, this flexibility
allows the RC to perform a more robust review.
Ben Engelby - ACES Power Marketing - 6, Group Name ACES Standards Collaborators - PRC-012-2 Project
Answer
Yes
Comment
We agree with the SDT that the implementation plan is appropriate.
Likes
0
Dislikes
0
Response
William Temple on Behalf of Mark Holman, PJM Interconnection, L.L.C. - 2
Answer
Yes
Comment
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72
PJM supports the comments submitted by the ISO/RTO Council.
Likes
0
Dislikes
0
Response
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC-ISONE
Answer
Yes
Comment
The rationale for R2 states that RC review “minimizes the possibility of a conflict of interest that could exist because of business
relationships among ….”. This explanatory purpose for R2 is not needed and in fact could prove untrue as not all RCs are independent
from TOs, GOs, etc.
The R3 rationale inserts the idea of “lack of dependability”. This can be understood differently by different parties. For a hardware
supplier, it can mean the equipment or technology is unreliable. And if taken to an extreme, this seems to open the path to requiring the
RC to decide which generators should run based on the individual generators’ forced outage rate (dependability rate?). We suggest this
phrase be stricken from the R3 explanatory.
For R4 the limited impact designation explanation, please clarify whether the reference to regions is meant to be an example of how the
SDT came to its decision for R4 or whether it is a reference of the authority of what regions can do. We believe it is the former and the
language should be improved.
The concept of 4.1.2 to “avoid adverse interactions” would seem to need some criteria for evaluating what “avoid” means. Rather than
state “avoid”, we suggest this requirement to be rewritten to state: “The RAS does not adversely impact the performance of other RAS,
and protection and control systems.”
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4.1.4.4. BES voltages shall be within post‐Contingency voltage limits and post‐Contingency voltage deviation limits as established by the
Transmission Planner and the Planning Coordinator. Some Planners don’t use voltage deviation criteria. This should it not be rewritten to
state “BES voltages shall be within the Planning Coordinator’s voltage criteria under pre and post contingency conditions”.
Likes
0
Dislikes
0
Response
Thank you for your comments.
The Rationale for Requirement R2 states that the RC review “minimizes” the possibility of a conflict of interest; it does not say that it
“eliminates” the possibility. While it is true that not all RCs are independent from RAS-entities, RCs are more likely to be independent
from RAS-entities than other functional model entities that would be more likely to be involved with the planning or implementation of a
RAS.
The phrase “lack of dependability” in the Rationale for Requirement R3 is referring only to the RAS. This is just an example of one of the
possible reliability issues with the RAS that the RC review is intended to uncover.
WECC and NPCC were cited because those are the only two Regions that classified RAS based upon certain criteria. The SPCS-SAMS team
also recognized these Regional classifications and made similar albeit different recommendations. The drafting team considered the
attributes of each of these regional classifications in creating the guidance for limited impact designation. The limited impact designation
is applicable on a continent-wide basis via NERC Reliability Standard PRC-012-2. Based on your comment, the drafting team modified the
language in the Rationale for Requirement R4.
The drafting team maintains that the current language “avoids adverse interactions” is clear and declines to make the suggested change.
The drafting team worded Requirement R4, Part 4.1.4 to reflect Requirement R5 of TPL-001-4 which requires PCs and TPs to have criteria
for post contingency voltage deviations.
Larry Heckert on Behalf of Kenneth Goldsmith, Alliant Energy Corporation Services, Inc. - 4
Answer
Yes
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Comment
Alliant Energy supports comments submitted by the MRO NERC Standards Review Forum.
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC No HQ and Dominion
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Oshani Pathirane on Behalf of Payam Farahbakhsh, Hydro One Networks, Inc. - 1, 3
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Andrew Pusztai - American Transmission Company, LLC - 1
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Jared Shakespeare - Peak Reliability - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Erika Doot - U.S. Bureau of Reclamation - 5
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Allie Gavin on Behalf of Michael Moltane, International Transmission Company Holdings Corporation - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
John Pearson on Behalf of Michael Puscas, ISO New England, Inc. - 2
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Teresa Czyz - Oglethorpe Power Corporation - 5
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Greg Davis on Behalf of Jason Snodgrass, Georgia Transmission Corporation - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Christy Koncz - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Thomas Foltz - AEP - 5
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Mike Smith - Manitoba Hydro - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Randi Heise - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion - RCS
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Gul Khan on Behalf of Rod Kinard, Oncor Electric Delivery - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Michael DeLoach - AEP - 3
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Michael DeLoach - AEP - 3
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
John Fontenot - Bryan Texas Utilities - 1
Answer
Yes
Comment
Likes
0
Dislikes
0
Response
Daniel Mason - City and County of San Francisco - 5
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Answer
Yes
Comment
Likes
0
Dislikes
0
Response
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PRC-012-2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 3 of PRC-012-2 corrects the applicability of the fill-in-the-blank standards (PRC-012-1,
PRC-013-1, and PRC-014-1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk-Power System, and incorporates the reliability objectives of
all the RAS-related standards. This draft contains nine requirements and measures, the
associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. This draft of PRC-012-2 is posted for a 10-day final ballot.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC-012-2 posted for informal comment
April 30 – May 20, 2015
Draft 1 of PRC-012-2 posted for 45-day formal comment period
with initial ballot
August 20 – October 5,
2015
Draft 2 of PRC-012-2 posted for 45-day formal comment period
with additional ballot
November 25, 2015 –
January 8, 2016
Draft 3 of PRC‐012‐2 posted for 45-day formal comment period
with additional ballot
February 3, 2016 –
March 18, 2016
Draft 3 of PRC‐012‐2 posted for 10‐day final ballot.
April 20 – 29, 2016
Anticipated Actions
Adoption by Board of Trustees
Draft 3 of PRC-012-2
April 2016
Date
May 2016
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PRC-012-2 – Remedial Action Schemes
When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
Number:
PRC-012-2
3.
Purpose:
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Planning Coordinator
4.1.3. RAS-entity – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC-012-2.
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B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement; i.e., removal from service must be completed prior
to implementation or retirement.
Functional modifications consist of any of the following:
• Changes to System conditions or Contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in-kind replacement; i.e., match the original
functionality of existing components
• Changes to RAS logic beyond correcting existing errors
• Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS-entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS-entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. Ideally, when there is more than one RAS-entity for
a RAS, the RAS-entities would collaborate and submit a single, coordinated Attachment 1
to the reviewing RC. In cases where a RAS crosses RC Area boundaries, each affected RC is
responsible for conducting either individual reviews or participating in a coordinated
review.
R1.
Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS-entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest area operational and reliability perspective of all
functional entities and an awareness of reliability issues in any neighboring RC Area. This
Wide Area purview facilitates the evaluation of interactions among separate RAS as well
as interactions among RAS and other protection and control systems. Review by the RC
also minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS-entity, Planning Coordinator (PC), Transmission Planner (TP),
or other entities that are likely to be involved in the planning or implementation of a RAS.
The RC is not expected to possess more information or ability than anticipated by their
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functional registration as designated by NERC. The RC may request assistance to perform
RAS reviews from other parties such as the PC or regional technical groups; however, the
RC will retain the responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each submitted RAS.
The time frame of four full calendar months is consistent with current utility and regional
practice; however, flexibility is provided by allowing the RC(s) and RAS-entity(ies) to
negotiate a mutually agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to each RAS-entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS-entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS-entity to respond to the reviewing RC following
identification of any reliability issue(s) is not necessary because the RAS-entity wants to
expedite the timely approval and subsequent implementation of the RAS.
A specific time period for the RC to respond to the RAS-entity following the RAS review is
also not necessary because the RC will be aware of (1) any reliability issues associated
with the RAS not being in service and (2) the RAS-entity’s schedule to implement the RAS
to address those reliability issues. Since the RC is the ultimate arbiter of BES operating
reliability, resolving reliability issues is a priority for the RC and serves as an incentive to
expeditiously respond to the RAS-entity.
R3.
Prior to placing a new or functionally modified RAS in service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability Coordinator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
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PRC-012-2 – Remedial Action Schemes
were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every five full calendar years. The purpose of the periodic RAS
evaluation is to verify the continued effectiveness and coordination of the RAS, as well as
to verify that, if a RAS single component malfunction or single component failure were to
occur, the requirements for BES performance would continue to be satisfied. A periodic
evaluation is required because changes in System topology or operating conditions may
change the effectiveness of a RAS or the way it impacts the BES.
RAS are unique and customized assemblages of protection and control equipment that
vary in complexity and impact on the reliability of the BES. In recognition of these
differences, RAS can be designated by the reviewing RC(s) as limited impact. A limited
impact RAS cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations. The “BES” qualifier in the preceding
statement modifies all of the conditions that follow it. Limited impact RAS are not subject
to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to
the design with minimal benefit to BES reliability. See the Supplemental Material for
more on the limited impact designation.
The standard recognizes the Local Area Protection Scheme (LAPS) classification in WECC
(Western Electricity Coordinating Council) and the Type III classification in NPCC
(Northeast Power Coordinating Council) as initially appropriate for limited impact
designation. A RAS implemented prior to the effective date of PRC-012-2 that has been
through the regional review processes of WECC or NPCC and is classified as either a Local
Area Protection Scheme (LAPS) in WECC or a Type III in NPCC is recognized as a limited
impact RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
For existing RAS, the initial performance of Requirement R4 must be completed within
five full calendar years of the effective date of PRC‐012‐2. For new or functionally
modified RAS, the initial performance of the requirement must be completed within five
full calendar years of the RAS approval date by the reviewing RC(s). Five full calendar
years was selected as the maximum time frame between evaluations based on the time
frames for similar requirements in Reliability Standards PRC-006, PRC-010, and PRC-014.
The RAS evaluation can be performed sooner if it is determined that material changes to
System topology or System operating conditions could potentially impact the
effectiveness or coordination of the RAS. System changes also have the potential to alter
the reliability impact of limited impact RAS on the BES. Requirement 4, Part 4.1.3
explicitly requires the periodic evaluation of limited impact RAS to verify the limited
impact designation remains applicable; the PC can use its discretion as to how this
evaluation is performed. The periodic RAS evaluation will typically lead to one of the
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following outcomes: 1) affirmation that the existing RAS is effective; 2) identification of
changes needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1
through 4.1.5) are planning analyses that may involve modeling of the interconnected
transmission system to assess BES performance. The Planning Coordinator (PC) is the
functional entity best suited to perform this evaluation because they have a wide area
planning perspective. To promote reliability, the PC is required to provide the results of
the evaluation to each impacted Transmission Planner and Planning Coordinator, in
addition to each reviewing RC and RAS-entity. In cases where a RAS crosses PC
boundaries, each affected PC is responsible for conducting either individual evaluations
or participating in a coordinated evaluation.
The previous version of this standard (PRC-012-1 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL-0010, TPL-002-0, and TPL-003-0) as that required of the Contingency for which it was
designed, and not exceed TPL-003-0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise,
consistent with PRC-012-1 Requirement 1, R1.4, the RAS should be designed so that its
whole or partial inadvertent operation due to a single component malfunction satisfies
the System performance requirements for the same Contingency for which the RAS was
designed.
If the RAS was installed for an extreme event in TPL-001-4 or for some other Contingency
or System condition not defined in TPL-001-4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL-001-4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.1.4.1 – 4.1.4.5) are the ones that
are common to all planning events P0-P7 listed in TPL-001-4.
R4.
Each Planning Coordinator, at least once every five full calendar years, shall:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for which
it was designed.
4.1.2. The RAS avoids adverse interactions with other RAS, and protection and
control systems.
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4.1.3. For limited impact 1 RAS, the inadvertent operation of the RAS or the
failure of the RAS to operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations.
4.1.4. Except for limited impact RAS, the possible inadvertent operation of the
RAS, resulting from any single RAS component malfunction satisfies all of
the following:
4.1.4.1.
The BES shall remain stable.
4.1.4.2.
Cascading shall not occur.
4.1.4.3.
Applicable Facility Ratings shall not be exceeded.
4.1.4.4.
BES voltages shall be within post-Contingency voltage limits
and post-Contingency voltage deviation limits as established
by the Transmission Planner and the Planning Coordinator.
4.1.4.5.
Transient voltage responses shall be within acceptable limits
as established by the Transmission Planner and the Planning
Coordinator.
4.1.5. Except for limited impact RAS, a single component failure in the RAS,
when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS-entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
1
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Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation was
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC-004-4
regarding the investigation of a Protection System Misoperation. To promote reliability,
each RAS-entity is required to provide the results of RAS operational performance
analyses that identified any deficiencies to its reviewing RC(s).
RAS-entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly
(Part 5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response
(Parts 5.1.3 and 5.1.4) was consistent with the intended functionality and design of the
RAS. Ideally, when there is more than one RAS-entity for a RAS, the RAS-entities would
collaborate to conduct and submit a single, coordinated operational performance
analysis.
R5.
Each RAS-entity, within 120 full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.1. The System events and/or conditions appropriately triggered the RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with participating RAS-entities and the reviewing Reliability Coordinator(s) in
accordance with Requirement R5.
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Rationale for Requirement R6: Deficiencies identified in the periodic RAS evaluation
conducted by the PC pursuant to Requirement R4, in the operational performance
analysis conducted by the RAS-entity pursuant to Requirement R5, or in the functional
test performed by the RAS-entity pursuant to Requirement R8, potentially pose a
reliability risk to the BES. To mitigate these potential reliability risks, Requirement R6
mandates that each RAS-entity develop a Corrective Action Plan (CAP) to address the
identified deficiency. The CAP contains the mitigation actions and associated timetable
necessary to remedy the specific deficiency. The RAS-entity may request assistance with
CAP development from other parties such as its Transmission Planner or Planning
Coordinator; however, the RAS-entity has the responsibility for compliance with this
requirement.
If the CAP requires that a functional change be made to a RAS, the RAS-entity will need to
submit information identified in Attachment 1 to the reviewing RC(s) prior to placing RAS
modifications in service per Requirement R1.
Depending on the complexity of the identified deficiency(ies), development of a CAP may
require studies, and other engineering or consulting work. A maximum time frame of six
full calendar months is specified for RAS-entity collaboration on the CAP development.
Ideally, when there is more than one RAS-entity for a RAS, the RAS-entities would
collaborate to develop and submit a single, coordinated CAP.
R6.
Each RAS-entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Longterm Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency pursuant to Requirement R5,
Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS-entity in
accordance with Requirement R6.
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Rationale for Requirement R7: Requirement R7 mandates each RAS-entity implement a
CAP (developed in Requirement R6) that mitigates the deficiencies identified in
Requirements R4, R5, or R8. By definition, a CAP is: “A list of actions and an associated
timetable for implementation to remedy a specific problem.” The implementation of a
properly developed CAP ensures that RAS deficiencies are mitigated in a timely manner.
Each reviewing Reliability Coordinator must be notified if CAP actions or timetables
change, and when the CAP is completed.
R7.
Each RAS-entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long-term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the reviewing Reliability
Coordinator(s) that documents the implementation, updating, or completion of a CAP
in accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non-Protection System (control) components of a RAS that are not addressed in PRC-005.
Protection System components that are part of a RAS are maintained in accordance with
PRC-005.
The six or twelve full calendar year test interval, which begins on the effective date of the
standard pursuant to the PRC-012-2 implementation plan, is a balance between the
resources required to perform the testing and the potential reliability impacts to the BES
created by undiscovered latent failures that could cause an incorrect operation of the
RAS. Extending to longer intervals increases the reliability risk to the BES posed by an
undiscovered latent failure that could cause an incorrect operation or failure of the RAS.
The RAS-entity is in the best position to determine the testing procedure and schedule
due to its overall knowledge of the RAS design, installation, and functionality. Functional
testing may be accomplished with end-to-end testing or a segmented approach. For
segmented testing, each segment of a RAS must be tested. Overlapping segments can be
tested individually negating the need for complex maintenance schedules and outages.
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The maximum allowable interval between functional tests is six full calendar years for RAS
that are not designated as limited impact RAS and twelve full calendar years for RAS that
are designated as limited impact RAS. The interval between tests begins on the date of
the most recent successful test for each individual segment or end-to-end test. A
successful test of one segment only resets the test interval clock for that segment. A
correct operation of a RAS qualifies as a functional test for those RAS segments which
operate (documentation for compliance with Requirement R5 Part 5.1). If an event causes
a partial operation of a RAS, the segments without an operation will require a separate
functional test within the maximum interval with the starting date determined by the
previous successful test of the segments that did not operate.
R8.
Each RAS-entity shall participate in performing a functional test of each of its RAS to
verify the overall RAS performance and the proper operation of non-Protection
System components: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
•
At least once every six full calendar years for all RAS not designated as limited
impact, or
•
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis for a correct RAS segment or an end-to-end
operation (Measure M5 documentation), or dated documentation demonstrating that
a functional test of each RAS segment or an end-to-end test was performed in
accordance with Requirement R8.
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Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high-level information on existing RAS that could potentially impact the
operational and/or planning activities of that entity. Attachment 3 lists the minimum
information required for the RAS database, which includes a summary of the RAS
initiating conditions, corrective actions, and System issues being mitigated. This
information allows an entity to evaluate the reliability need for requesting more detailed
information from the RAS-entities identified in the database contact information. The RC
is the appropriate entity to maintain the database because the RC receives the required
database information when a new or modified RAS is submitted for review. The twelve
full calendar month time frame is aligned with industry practice and allows sufficient time
for the RC to collect the appropriate information from RAS-entities and update the RAS
database.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS-entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1, R3, R5, R6, R7, and R8, and Measures M1, M3, M5, M6, M7,
and M8 since the last audit, unless directed by its Compliance Enforcement
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Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M2 and M9 since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS-entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non-compliant, it shall
keep information related to the non-compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS-entity failed to
provide the information
identified in Attachment 1 to
each Reliability Coordinator
prior to placing a new or
functionally modified RAS in
service or retiring an existing
RAS in accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30 full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90 full
calendar days.
Draft 3 of PRC-012-2
April 2016
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
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R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS-entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS in
service or retiring an existing
RAS in accordance with
Requirement R3.
R4.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 90 full
calendar days.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1.1 through 4.1.5.
Draft 3 of PRC-012-2
April 2016
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate two or more of
the Parts 4.1.1 through 4.1.5.
OR
Page 15 of 51
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
R5.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by less than or
equal to 10 full calendar
days.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to address one of the
Parts 5.1.1 through 5.1.4.
Draft 3 of PRC-012-2
April 2016
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 30 full
calendar days.
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to address two or
more of the Parts 5.1.1
through 5.1.4.
Page 16 of 51
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
(Part 5.2) to one or more of
the reviewing Reliability
Coordinator(s).
OR
The RAS-entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10 full calendar days.
Draft 3 of PRC-012-2
April 2016
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30 full
calendar days.
OR
The RAS-entity developed a
Corrective Action Plan but
failed to submit it to one or
Page 17 of 51
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
more of its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6.
OR
The RAS-entity failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS-entity implemented N/A
a CAP in accordance with
Requirement R7, Part 7.1,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed, or failed
to notify (Part 7.3) each of
the reviewing Reliability
Coordinator(s) of the
updated CAP or completion
of the CAP.
N/A
The RAS-entity failed to
implement a CAP in
accordance with
Requirement R7, Part 7.1.
R8.
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by less than
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 60 full calendar days
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 90 full calendar days.
Draft 3 of PRC-012-2
April 2016
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 30 full calendar days
Page 18 of 51
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
R9.
Moderate VSL
High VSL
or equal to 30 full calendar
days.
but less than or equal to 60
full calendar days.
but less than or equal to 90
full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30 full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
Draft 3 of PRC-012-2
April 2016
Severe VSL
OR
The RAS-entity failed to
perform the functional test
for a RAS as specified in
Requirement R8.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90 full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
Page 19 of 51
PRC-012-2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
0
Date
Action
February 8, 2005 Adopted by the Board of Trustees
March 16, 2007
Identified by Commission as “fill-in-the-blank” with
no action taken on the standard
1
November 13,
2014
Adopted by the Board of Trustees
1
November 19,
2015
Accepted by Commission for informational
purposes only
0
2
Draft 3 of PRC-012-2
April 2016
Change Tracking
Adopted by Board of Trustees
New
Page 20 of 51
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified 2 RAS that the RAS-entity must document and provide to
the reviewing Reliability Coordinator(s) (RC). If an item on this list does not apply to a
specific RAS, a response of “Not Applicable” for that item is appropriate. When RAS are
submitted for functional modification review and approval, only the proposed modifications
to that RAS require review; however, the RAS-entity must provide a summary of the existing
functionality. The RC may request additional information on any aspect of the RAS as well as
any reliability issue related to the RAS. Additional entities (without decision authority) may
be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one-line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre- and post-modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS-entity and contact information.
c. Expected or actual in-service date; most recent RC-approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under- or overvoltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
f. Action(s) to be taken by the RAS.
g. Identification of limited impact 3 RAS.
h. Any additional explanation relevant to high-level understanding of the RAS.
Functionally modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
3 A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
2
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Attachments
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS-entity proposal and justification for limited impact designation, if applicable.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
8. Identification of other affected RCs.
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Attachments
III. Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in service or is being
maintained.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective.
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS-entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
Draft 3 of PRC-012-2
April 2016
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability-related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified 4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any aspect of the RAS as well as any reliability issue related to the RAS. If a
checklist item is not relevant to a particular RAS, it should be noted as “Not Applicable.” If
reliability considerations are identified during the review, the considerations and the proposed
resolutions should be documented with the remaining applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The designed timing of RAS operation(s) is appropriate to its BES performance
objectives.
3. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
4. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
5. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate, have been identified.
6. Determination whether or not the RAS is limited impact. 5 A RAS designated as limited
impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations.
7. Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
Functionally modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
5 A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
4
Draft 3 of PRC-012-2
April 2016
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Attachments
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
8. The effects of future BES modifications on the design and operation of the RAS have
been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. Except for limited impact RAS as determined by the RC, a single component failure in a
RAS does not prevent the BES from meeting the same performance requirements as
those required for the events and conditions for which the RAS is designed.
3. The RAS design facilitates periodic testing and maintenance.
4. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
Draft 3 of PRC-012-2
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Page 25 of 51
Attachments
Attachment 3
Database Information
1. RAS name.
2. Each RAS-entity and contact information.
3. Expected or actual in-service date; most recent RC-approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under- or over-voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact 6 RAS.
8. Any additional explanation relevant to high-level understanding of the RAS.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
6
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Supplemental Material
Technical Justification
4.1.1 Reliability Coordinator
The Reliability Coordinator (RC) is the best-suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The Wide
Area purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS-entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best-suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS-entity
The RAS-entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RASentity has sole responsibility for all the activities assigned within the standard to the RAS-entity.
If the RAS (RAS components) have more than one owner, then each separate RAS component
owner is a RAS-entity and is obligated to participate in various activities identified by the
Requirements.
The standard does not stipulate particular compliance methods. RAS-entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS-entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS-entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Limited impact
RAS are unique and customized assemblages of protection and control equipment that vary in
complexity and impact on the reliability of the BES. These differences in RAS design, action, and
risk to the BES are identified and verified within the construct of Requirements R1-R4 of PRC012-2.
The reviewing RC has the authority to designate a RAS as limited impact if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
Draft 3 of PRC-012-2
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Supplemental Material
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The reviewing RC makes the final determination as to whether a RAS qualifies for
the limited impact designation based upon the studies and other information provided with the
Attachment 1 submittal by the RAS-entity.
The standard recognizes the Local Area Protection Scheme (LAPS) classification in WECC
(Western Electricity Coordinating Council) and the Type III classification in NPCC (Northeast
Power Coordinating Council) as initially appropriate for limited impact designation. The
following information describing the aforementioned WECC and NPCC RAS is excerpted from
the respective regional documentation 7.The drafting team notes that the information below
represents the state of the WECC and NPCC regional processes at the time of this standard
development and is subject to change before the effective date of PRC-012-2.
WECC: Local Area Protection Scheme (LAPS)
A Remedial Action Scheme (RAS) whose failure to operate would NOT result in any of the
following:
•
Violations of TPL-001-WECC-RBP System Performance RBP,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
NPCC: Type III
An SPS whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for
classification:
Significant adverse impact – With due regard for the maximum operating capability of the
affected systems, one or more of the following conditions arising from faults or disturbances,
shall be deemed as having significant adverse impact:
a. system instability;
b. unacceptable system dynamic response or equipment tripping;
c. voltage levels in violation of applicable emergency limits;
d. loadings on transmission facilities in violation of applicable emergency limits;
e. unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and
number of system elements contained will vary based on system characteristics. A local area
may be relatively large geographically with relatively few buses in a sparse system, or be
WECC Procedure to Submit a RAS for Assessment Information Required to Assess the Reliability of a RAS Guideline, Revised
10/28/2013 | NPCC Regional Reliability Reference Directory # 7, Special Protection Systems, Version 2, 3/31/2015
7
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Supplemental Material
relatively small geographically with a relatively large number of buses in a densely networked
system.
A RAS implemented prior to the effective date of PRC-012-2 that has been through the regional
review processes of WECC or NPCC and classified as either a Local Area Protection Scheme
(LAPS) in WECC or a Type III in NPCC, is recognized as a limited impact RAS upon the effective
date of PRC-012-2 for the purposes of this standard and is subject to all applicable
requirements.
To propose an existing RAS (a RAS implemented prior to the effective date of PRC-012-2) be
designated as limited impact by the reviewing RC, the RAS-entity must prepare and submit the
appropriate Attachment 1 information that includes the technical justification (evaluations)
documenting that the System can meet the performance requirements (specified in
Requirement R4, Parts 4.1.4 and 4.1.5) resulting from a single RAS component malfunction or
failure, respectively.
There is nothing that precludes a RAS-entity from working with the reviewing RC during the
implementation period of PRC-012-2, in anticipation of the standard becoming enforceable.
However, even if the reviewing RC determines the RAS qualifies as limited impact, the
designation is not relevant until the standard becomes effective. Until then, the existing
regional processes remain in effect as well as the existing RAS classifications or lack thereof.
An example of a scheme that could be recognized as a limited impact RAS is a load shedding or
generation rejection scheme used to mitigate the overload of a BES transmission line. The
inadvertent operation of such a scheme would cause the loss of either a certain amount of
generation or load. The evaluation by the RAS-entity should demonstrate that the loss of this
amount of generation or load, without the associated contingency for RAS operation actually
occurring, is acceptable and not detrimental to the reliability of BES; e.g., in terms of frequency
and voltage stability. The failure of that scheme to operate when intended could potentially
lead to the overloading of a transmission line beyond its acceptable rating. The RAS-entity
would need to demonstrate that this overload, while in excess of the applicable Facility Rating,
is not detrimental to the BES outside the contained area (predetermined by studies) affected by
the contingency.
Other examples of limited impact RAS include:
•
A scheme used to protect BES equipment from damage caused by overvoltage through
generation rejection or equipment tripping.
•
A centrally-controlled undervoltage load shedding scheme used to protect a contained
area (predetermined by studies) of the BES against voltage collapse.
•
A scheme used to trip a generating unit following certain BES Contingencies to prevent
the unit from going out of synch with the System; where, if the RAS fails to operate and
the unit pulls out of synchronism, the resulting apparent impedance swings do not
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Supplemental Material
result in the tripping of any Transmission System Elements other than the generating
unit and its directly connected Facilities.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Functional modifications consists of any of the following:
•
Changes to System conditions or Contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original
functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in-kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that uses similar
functions. For instance, if a RAS included a CO-11 relay which was replaced by an IAC-53 relay,
that would be an in-kind replacement. If the CO-11 relay were replaced by a microprocessor
SEL-451 relay that used only the same functions as the original CO-11 relay, that would also be
an in-kind replacement; however, if the SEL-451 relay was used to add new logic to what the
CO-11 relay had provided, then the replacement relay would be a functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. For example, System conditions require a RAS to be armed when the
combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to Requirement
R4, or other assessment, indicates that the arming level should be reduced to 450 MW without
requiring any other RAS changes that would not be a functional modification. Similarly, if a RAS
is designed to shed load to reduce loading on a particular line below 1000 amps, then a change
in the load shedding trigger from 1000 amps to 1100 amps would not be a functional
modification.
Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs to the RAS) and the logic to recognize the specific line outages would
Draft 3 of PRC-012-2
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Supplemental Material
change, while the generation reduction (RAS output) requirement may or may not change,
depending on which line is out of service. These required RAS changes would be a functional
modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for such functional modifications
may be identified in several ways including but not limited to the Planning evaluations pursuant
to R4, incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning
assessments related to future additions or modifications of other facilities.
See Item 4a in the Implementation Section of Attachment 1 in the Supplemental Material
section for typical RAS components for which a failure may be considered. The RC has the
discretion to make the final determination regarding which components should be regarded as
RAS components during its review.
To facilitate a review that promotes reliability, the RAS-entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS-entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS-entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RASentity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS-entity(ies). An independent review by a multi-disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the widest
area reliability perspective of all functional entities and an awareness of reliability issues in
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Supplemental Material
neighboring RC Areas. This Wide Area purview facilitates the evaluation of interactions among
separate RAS as well as interactions among the RAS and other protection and control systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS-entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement. It is recognized that the RC does not
possesses more information or ability than anticipated by their functional registration as
designated by NERC. The NERC Functional Model is a guideline for the development of
standards and their applicability and does not contain compliance requirements. If Reliability
Standards address functions that are not described in the model, the Reliability Standard
requirements take precedence over the Functional Model. For further reference, please see the
Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
for review. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
Requirement R3
Requirement R3 mandates that each RAS-entity resolve all reliability issues (pertaining to its
RAS) identified during the RAS review by the reviewing Reliability Coordinators. Examples of
reliability issues include a lack of dependability, security, or coordination. RC approval of a RAS
is considered to be obtained when the reviewing RC’s feedback to each RAS-entity indicates
that either no reliability issues were identified during the review or all identified reliability
issues were resolved to the RC’s satisfaction.
Dependability is a component of reliability that is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over-tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability that is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re-configuring the System. Such actions, if inadvertently taken, are undesirable
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and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC012-2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS-entity or the reviewing RC(s) may
have alternative ideas or methods available to resolve the issue(s). In either case, the concern
needs to be resolved in deference to reliability, and the RC has the final decision.
A specific time period for the RAS-entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS-entity to effect a timely
implementation.
A specific time period for the RC to respond to the RAS-entity following the RAS review is also
not necessary because the RC will be aware of (1) any reliability issues associated with the RAS
not being in service and (2) the RAS-entity’s schedule to implement the RAS to address those
reliability issues. Since the RC is the ultimate arbiter of BES operating reliability, resolving
reliability issues is a priority for the RC and serves as an incentive to expeditiously respond to
the RAS-entity.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every five
full calendar years. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it interacts with and impacts the
BES.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate,
cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
instability, voltage collapse, or unacceptably damped oscillations. Limited impact RAS are not
subject to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to the
design with minimal benefit to BES reliability.
A RAS implemented after the effective date of this standard can only be designated as limited
impact by the reviewing RC(s). A RAS implemented prior to the effective date of PRC-012-2 that
has been through the regional review processes of WECC or NPCC and is classified as either a
Local Area Protection Scheme (LAPS) in WECC or a Type III in NPCC is recognized as a limited
impact RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
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Requirement R4 also clarifies that the RAS single component failure and inadvertent operation
tests do not apply to RAS which are determined to be limited impact. Requiring a limited impact
RAS to meet the single component failure and inadvertent operation tests would just add
complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within five full
calendar years of the effective date of PRC‐012‐2. For new or functionally modified RAS, the
initial performance of the requirement must be completed within five full calendar years of the
RAS approval date by the reviewing RC(s). Five full calendar years was selected as the maximum
time frame between evaluations based on the time frames for similar requirements in
Reliability Standards PRC-006, PRC-010, and PRC-014. The RAS evaluation can be performed
sooner if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. System
changes also have the potential to alter the reliability impact of limited impact RAS on the BES.
Requirement 4, Part 4.1.3 explicitly requires the periodic evaluation of limited impact RAS to
verify the limited impact designation remains applicable. The periodic RAS evaluation will
typically lead to one of the following outcomes: 1) affirmation that the existing RAS is effective;
2) identification of changes needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.5) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The PC is the functional entity best suited to perform the
analyses because they have a wide-area planning perspective. To promote reliability, the PC is
required to provide the results of the evaluation to each impacted Transmission Planner and
Planning Coordinator, in addition to each reviewing RC and RAS-entity. In cases where a RAS
crosses PC boundaries, each affected PC is responsible for conducting either individual
evaluations or participating in a coordinated evaluation.
The intent of Requirement R4, Part 4.1.4 is to verify that the possible inadvertent operation of
the RAS (other than limited impact RAS), caused by the malfunction of a single component of
the RAS, meet the same System performance requirements as those required for the
Contingency(ies) or System conditions for which it is designed. If the RAS is designed to meet
one of the planning events (P0-P7) in TPL-001-4, the possible inadvertent operation of the RAS
must meet the same performance requirements listed in the standard for that planning event.
The requirement clarifies that the inadvertent operation to be considered is only that caused by
the malfunction of a single RAS component. This allows features to be designed into the RAS to
improve security, such that inadvertent operation due to malfunction of a single component is
prevented; otherwise, the RAS inadvertent operation must satisfy Requirement R4, Part 4.1.4.
The intent of Requirement R4, Part 4.1.4 is also to verify that the possible inadvertent operation
of the RAS (other than limited impact RAS) installed for an extreme event in TPL-001-4 or for
some other Contingency or System conditions not defined in TPL-001-4 (therefore without
performance requirements), meet the minimum System performance requirements of Category
P7 in Table 1 of NERC Reliability Standard TPL-001-4. However, instead of referring to the TPL
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standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.4.1 – 4.1.4.5) are the ones that are common to all planning events (P0-P7) listed in
TPL-001-4.
With reference to Requirement 4, Part 4.1.4, note that the only differences in performance
requirements among the TPL (P0-P7) events (not common to all of them) concern NonConsequential Load Loss and interruption of Firm Transmission Service. It is not necessary for
Requirement R4, Part 4.1.4 to specify performance requirements related to these areas
because a RAS is only allowed to drop non-consequential load or interrupt Firm Transmission
Service if that action is allowed for the Contingency for which it is designed. Therefore, the
inadvertent operation should automatically meet Non-Consequential Load Loss or interrupting
Firm Transmission Service performance requirements for the Contingency(ies) for which it was
designed.
The intent of Requirement R4, Part 4.1.5 is to verify that a single component failure in a RAS,
other than limited impact RAS, when the RAS is intended to operate, does not prevent the BES
from meeting the same performance requirements (defined in Reliability Standard TPL-001-4 or
its successor) as those required for the events and conditions for which the RAS is designed.
This analysis is needed to ensure that changing System conditions do not result in the single
component failure requirement not being met.
The following is an example of a single component failure causing the System to fail to meet the
performance requirements for the P1 event for which the RAS was installed. Consider the
instance where a three-phase Fault (P1 event) results in a generating plant becoming unstable
(a violation of the System performance requirements of TPL-001-4). To resolve this, a RAS is
installed to trip a single generating unit which allows the remaining units at the plant to remain
stable. If failure of a single component (e.g., relay) in the RAS results in the RAS failing to
operate for the P1 event, the generating plant would become unstable (failing to meet the
System performance requirements of TPL-001-4 for a P1 event).
Requirement R4, Part 4.1.5 does not mandate that all RAS have redundant components. For
example:
•
Consider the instance where a RAS is installed to mitigate an extreme event in TPL-0014. There are no System performance requirements for extreme events; therefore, the
RAS does not need redundancy to meet the same performance requirements as those
required for the events and conditions for which the RAS was designed.
•
Consider a RAS that arms more load or generation than necessary such that failure of
the RAS to drop a portion of load or generation due to that single component failure will
still result in satisfactory System performance, as long as tripping the total armed
amount of load or generation does not cause other adverse impacts to reliability.
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The scope of the periodic evaluation does not include a new review of the physical
implementation of the RAS, as this was confirmed by the RC during the initial review and
verified by subsequent functional testing. However, it is possible that a RAS design which
previously satisfied requirements for inadvertent RAS operation and single component failure
by means other than component redundancy may fail to satisfy these requirements at a later
time, and must be evaluated with respect to the current System. For example, if the actions of a
particular RAS include tripping load, load growth could occur over time that impacts the
amount of load to be tripped. These changes could result in tripping too much load upon
inadvertent operation and result in violations of Facility Ratings. Alternatively, the RAS might be
designed to trip more load than necessary (i.e., “over trip”) in order to satisfy single component
failure requirements. System changes could result in too little load being tripped and
unacceptable BES performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC-004-4 regarding
the investigation of a Protection System Misoperation; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
the RAS-entity(s) is required to provide the results of RAS operational performance analyses to
its reviewing RC(s) if the analyses revealed a deficiency.
The RAS-entity(ies) may need to collaborate with its associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS-entity for a RAS, the RAS-entities would collaborate to conduct and
submit a single, coordinated operational performance analysis.
Requirement R6
RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may be identified
in the periodic RAS evaluation conducted by the PC in Requirement R4, in the operational
analysis conducted by the RAS-entity in Requirement R5, or in the functional test performed by
the RAS-entity(ies) in Requirement R8. To mitigate potential reliability risks, Requirement R6
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mandates that each RAS-entity participate in developing a CAP that establishes the mitigation
actions and timetable necessary to address the deficiency.
The RAS-entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS-entity(ies) may request assistance with development of the
CAP from other parties such as its Transmission Planner or Planning Coordinator; however, the
RAS-entity has the responsibility for compliance with this requirement.
A CAP may require functional changes be made to a RAS. In this case, Attachment 1 information
must be submitted to the reviewing RC(s), an RC review must be performed to obtain RC
approval before the RAS-entity can place RAS modifications in service, per Requirements R1,
R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering or consulting work. A timeframe of six full calendar months is allotted to allow
enough time for RAS-entity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. Ideally, when there is more than one RASentity for a RAS, the RAS-entities would collaborate to develop and submit a single, coordinated
CAP. A RAS deficiency may require the RC or Transmission Operator to impose operating
restrictions so the System can operate in a reliable way until the RAS deficiency is resolved. The
possibility of such operating restrictions will incent the RAS-entity to resolve the issue as quickly
as possible.
The following are example situations of when a CAP is required:
•
A determination after a RAS operation/non-operation investigation that the RAS did not
meet performance expectations or did not operate as designed.
•
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
•
Equipment failures.
•
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
Requirement R7 mandates that each RAS-entity implement its CAP developed in Requirement
R6 which mitigates the deficiencies identified in Requirements R4, R5, or R8. By definition, a
CAP is: “A list of actions and an associated timetable for implementation to remedy a specific
problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. If the CAP is changed, the RAS-entity must notify the reviewing Reliability
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Coordinator(s). The RAS-entity must also notify the Reliability Coordinator(s) when the CAP has
been completed.
The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS-entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non-Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in-service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC-005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed with minimum impact to the
BES and should align with expected results. The RAS-entity is in the best position to determine
the testing procedure and schedule due to their overall knowledge of the RAS design,
installation, and functionality. Periodic testing provides the RAS-entity assurance that latent
failures may be identified and also promotes identification of changes in the System that may
have introduced latent failures.
The six and twelve full calendar year functional testing intervals are greater than the annual or
bi-annual periodic testing performed in some NERC Regions. However, these intervals are a
balance between the resources required to perform the testing and the potential reliability
impacts to the BES created by undiscovered latent failures that could cause an incorrect
operation of the RAS. Longer test intervals for limited impact RAS are acceptable because
incorrect operations or failures to operate present a low reliability risk to the Bulk Power
System.
Functional testing is not synonymous with end-to-end testing. End-to-end testing is an
acceptable method but may not be feasible for many RAS. When end-to-end testing is not
possible, a RAS-entity may use a segmented functional testing approach. The segments can be
tested individually negating the need for complex maintenance schedules. In addition, actual
RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does not
operate in its entirety during a System event or System conditions do not allow an end-to-end
scheme test, then the segmented approach should be used to fulfill this Requirement.
Functional testing includes the testing of all RAS inputs used for detection, arming, operating,
and data collection. Functional testing, by default operates the processing logic and
infrastructure of a RAS, but focuses on the RAS inputs as well as the actions initiated by RAS
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outputs to address the System condition(s) for which the RAS is designed. All segments and
components of a RAS must be tested or have proven operations within the applicable
maximum test interval to demonstrate compliance with the Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC-005, Table 1-1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up to the protective
relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3-8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well-defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component-level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of Contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real-time) to
the Transmission Operator via PRC-001, Requirement R6, then to the RC via TOP-001-3,
Requirement R8. See Phase 2 of Project 2007-06 for the mapping document from PRC-001 to
other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
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is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end-to-end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS-entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
maximum test interval that started on the date of the previous successful test of those (nonoperating) segments in order to be compliant with Requirement R8.
Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available. Attachment 3 contains the minimum information that is
required to be included about each RAS listed in the database. Additional information can be
requested by the RC.
The database enables the RC to provide other entities high-level information on existing RAS
that could potentially impact the operational and/or planning activities of that entity. The
information provided is sufficient for an entity with a reliability need to evaluate whether the
RAS can impact its System. For example, a RAS performing generation rejection to mitigate an
overload on a transmission line may cause a power flow change within an adjacent entity area.
This entity should be able to evaluate the risk that a RAS poses to its System from the high-level
information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS-entity from the RC.
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Process Flow Diagram
The diagram below depicts the process flow of the PRC-012-2 requirements.
New RAS proposed
or RAS modified/
retired
Attachment 1
Attachment 2
R1
RAS-entity submits
RAS to RC for review
R2
RC Review Process
For new, modified,
or removal of RAS
RC Approves RAS as is
R3
RAS-entity accepts
approval
R9
RC updates RAS
database
Modify RAS per RC
direction
RC identified issues
With RAS
R3
RAS-entity
addresses issues
RAS
Database
Proposed alternative
to RC direction
Dated Report /
Analysis
Dated
communications
with RAS-entity(ies)
& RC
Yes
reset 5-year clock
Does CAP identify
RAS modification?
No
R4
PC – 5-year review
of RAS in the
planning area
RAS 5-year review
RAS operation or
non operation as
intended
Any deficiencies
identified?
R5
RAS entity determines if RAS
operated as intended (120 days
or an accepted alternative
schedule)
R6
RAS-entity proposes
Corrective Action
Plan within 6
months
Yes
No
R7
RAS-entity
implement the CAP
and update the CAP
until complete
Dated
documentation of
non operation or
operation not as
intended to RC
No
Work Management
documents
Maintenance
Records
Yes
Dated
documentation to
state correct
operation
Yes
At least once every 6
years (12 years –
limited impact)
R8
Perform functional
test of RAS
Any deficiencies
identified?
No
Dated
documentation of
functional testing
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS-entity(ies) to provide a detailed list of information
describing the RAS to the reviewing RC. If there are multiple RAS-entities for a single RAS,
information will be needed from all RAS-entities. Ideally, in such cases, a single RAS-entity will
take the lead to compile all the data identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide-ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified 8 RAS that the RAS-entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS-entity
provides a summary of the existing RAS functionality.
I. General
1. Information such as maps, one-line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single-line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre- and post-modified functionality of the RAS.
8
Functionally modified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
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3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC-012-2, Requirements R5 and R7]
Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name.
b. Each RAS-entity and contact information.
c. Expected or actual in-service date; most recent (Requirement R3) RC-approval date;
most recent five full calendar year (Requirement R4) evaluation date; and, date of
retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under-/over-voltage,
slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (initiating conditions).
f. Corrective action taken by the RAS.
g. Identification of limited impact 9 RAS.
h. Any additional explanation relevant to high level understanding of the RAS.
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II. Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical System
Contingencies or other operating conditions when RAS action is intended to occur.
If no arming conditions are required, this should also be stated.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
9
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c. Event-based RAS are triggered by specific Contingencies that initiate mitigating
action. Condition-based RAS may also be initiated by specific Contingencies, but
specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed. [Reference NEC Reliability Standard PRC-014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS-related operations.
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC-014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. RAS-entity proposal and justification for limited impact designation, if applicable.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of PRC-012-2 that has been through the
regional review processes of WECC or NPCC and is classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited impact
RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
[Reference NERC Reliability Standard PRC-012, R1.4]
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a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC-012, R1.5 and PRC-014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or reconfiguring the System. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available Fault duty,
which can affect distance relay overcurrent (“fault detector”) supervision and ground
overcurrent protection coordination.
8. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be
designed to be secure. Several types of devices have been commonly used as disturbance,
condition, or status detectors:
•
Line open status (event detectors),
•
Protective relay inputs and outputs (event and parameter detectors),
•
Transducer and IED (analog) inputs (parameter and response detectors),
•
Rate of change (parameter and response detectors).
DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by
PRC-005. However, redundant RAS, when used, should be supplied from separately
protected (fused or breakered) circuits.
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Communications: Telecommunications Channels
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non-deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel
or equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS-entity, or
perhaps leased from another entity familiar with the necessary reliability requirements.
All channel equipment should be monitored and alarmed to the dispatch center so that
timely diagnostic and repair action shall take place upon failure. Publicly switched
telephone networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel
working on the channel can readily identify the proper circuit. Channels between entities
should be identified with a common name at all terminals.
Transfer Trip
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions
may be required at different arming levels or for different Contingencies. Scheme logic
may be achievable by something as simple as wiring a few auxiliary relay contacts or by
much more complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units
(RTUs), and logic processors. Single-function relays have been used historically to
implement RAS, but this approach is now less common except for very simple new RAS or
minor additions to existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS
actions at the sites where action is required.
Monitoring by SCADA/EMS should include at least
•
Whether the scheme is in service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in service or out of service.
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For RAS that are armed automatically, these two states are independent because
a RAS that has been placed in service may be armed or unarmed based on
whether the automatic arming criteria have been met.
•
The current operational state of the scheme (available or not).
•
In cases where the RAS requires single component failure performance; e.g.,
redundancy, the minimal status indications should be provided separately for each
RAS.
The minimum status is generally sufficient for operational purposes; however,
where possible it is often useful to provide additional information regarding
partial failures or the status of critical components to allow the RAS-entity to
more efficiently troubleshoot a reported failure. Whether this capability exists
will depend in part on the design and vintage of equipment used in the RAS.
While all schemes should provide the minimum level of monitoring, new
schemes should be designed with the objective of providing monitoring at least
similar to what is provided for microprocessor-based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line-charging current;
c. Breaker trip coil current monitoring—typically used when high-speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of the
aforementioned, out of step, etc. are dependent on specific scheme requirements,
but some forms may substitute for or enhance other monitoring described in items
‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in service or is being
maintained.
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In this context, a multifunction device (e.g., microprocessor-based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor-based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi-function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective. [Reference NERC Reliability Standard PRC-012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement.
Acceptable methods to achieve this objective include, but are not limited to the
following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
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Protective or auxiliary relays used by the RAS.
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Supplemental Material
ii.
Communications systems necessary for correct operation of the RAS.
iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation due to that single component failure will still result in
satisfactory System performance, as long as tripping the total armed amount of load
or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re-dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS-entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies and technical justifications, if applicable, upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
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Supplemental Material
Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent-wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability-related considerations relevant to various aspects of RAS design and
implementation.
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
•
The name used to identify the RAS.
2. Each RAS-entity and contact information.
•
A reliable phone number or email address should be included to contact each RAS-entity
if more information is needed.
3. Expected or actual in-service date; most recent (Requirement R3) RC-approval date; most
recent five full calendar year (Requirement R4) evaluation date; and, date of retirement, if
applicable.
•
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under-/over-voltage, slow voltage
recovery).
•
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the Contingencies or System conditions for which the RAS was designed
(initiating conditions).
•
A high level summary of the conditions/Contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
•
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
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Supplemental Material
7. Identification of limited impact 10 RAS.
•
Specify whether or not the RAS is designated as limited impact.
8. Any additional explanation relevant to high-level understanding of the RAS.
•
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
10
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PRC-012-2 – Remedial Action Schemes
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
Draft 23 of PRC-012-2 corrects the applicability of the fill-in-the-blank standards (PRC-012-1,
PRC-013-1, and PRC-014-1) by assigning the requirement responsibilities to the specific users,
owners, and operators of the Bulk-Power System, and incorporates the reliability objectives of
all the RAS-related standards. This draft contains nine requirements and measures, the
associated rationale boxes and corresponding technical guidelines. There are also three
attachments within the draft standard that are incorporated via references in the
requirements. This draft of PRC-012-2 is posted for a 4510-day formal comment period with a
parallelfinal ballot in the last ten days of the comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 12, 2014
SAR posted for comment
February 18, 2014
Standards Committee approved the SAR
June 10, 2014
Draft 1 of PRC-012-2 posted for informal comment
April 30 – May 20, 2015
Draft 1 of PRC-012-2 posted for 45-day formal comment period
with initial ballot
August 20 – October 5,
2015
Draft 2 of PRC-012-2 posted for 45-day formal comment period
with additional ballot
November 25, 2015 –
January 8, 2016
Draft 3 of PRC‐012‐2 posted for 45-day formal comment period
with additional ballot
February 3, 2016 –
March 18, 2016
Draft 3 of PRC‐012‐2 posted for 10‐day final ballot.
April 20 – 29, 2016
Anticipated Actions
Date
10-day final ballot
April 2016
Adoption by Board of TrusteesNERC Board (Board) adoption
May 2016
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When this standard receives Board adoption, the rationale boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Remedial Action Schemes
2.
Number:
PRC-012-2
3.
Purpose:
To ensure that Remedial Action Schemes (RAS) do not introduce
unintentional or unacceptable reliability risks to the Bulk Electric System
(BES).
4.
Applicability:
4.1. Functional Entities:
4.1.1. Reliability Coordinator
4.1.2. Planning Coordinator
4.1.3. RAS-entity – the Transmission Owner, Generator Owner, or Distribution
Provider that owns all or part of a RAS
4.2. Facilities:
4.2.1. Remedial Action Schemes (RAS)
5.
Effective Date: See the Implementation Plan for PRC-012-2.
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B. Requirements and Measures
Rationale for Requirement R1: Each Remedial Action Scheme (RAS) is unique and its
action(s) can have a significant impact on the reliability and integrity of the Bulk Electric
System (BES). Therefore, a review of a proposed new RAS or an existing RAS proposed for
functional modification or retirement; i.e., removal from service must be completed prior
to implementation or retirement.
Functional modifications consist of any of the following:
• Changes to System conditions or Contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in-kind replacement; i.e., match the original
functionality of existing components
• Changes to RAS logic beyond correcting existing errors
• Changes to redundancy levels; i.e., addition or removal
To facilitate a review that promotes reliability, the RAS-entity must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and
supporting documentation are identified in Attachment 1 of this standard, and
Requirement R1 mandates that the RAS-entity provide them to the reviewing Reliability
Coordinator (RC). The RC (reviewing RC) that coordinates the area where the RAS is
located is responsible for the review. Ideally, when there is more than one RAS-entity for
a RAS, the RAS-entities would collaborate and submit a single, coordinated Attachment 1
to the reviewing RC. In cases where a RAS crosses RC Area boundaries, each affected RC is
responsible for conducting either individual reviews or participating in a coordinated
review.
R1.
Prior to placing a new or functionally modified RAS in- service or retiring an existing
RAS, each RAS-entity shall provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is located. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M1. Acceptable evidence may include, but is not limited to, a copy of the Attachment 1
documentation and the dated communications with the reviewing Reliability
Coordinator(s) in accordance with Requirement R1.
Rationale for Requirement R2: The RC is the functional entity best suited to perform the
RAS review because it has the widest- area operational and reliability perspective of all
functional entities and an awareness of reliability issues in any neighboring RC Area. This
Wide Area purview facilitates the evaluation of interactions among separate RAS as well
as interactions among RAS and other protection and control systems. Review by the RC
also minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS-entity, Planning Coordinator (PC), Transmission Planner (TP),
or other entities that are likely to be involved in the planning or implementation of a RAS.
The RC is not expected to possess more information or ability than anticipated by their
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PRC-012-2 – Remedial Action Schemes
functional registration as designated by NERC. The RC may request assistance to perform
RAS reviews from other parties such as the PC or regional technical groups; however, the
RC will retain the responsibility for compliance with this requirement.
Attachment 2 of this standard is a checklist the RC can use to identify design and
implementation aspects of RAS and facilitate consistent reviews for each submitted RAS.
The time frame of four full calendar months is consistent with current utility and regional
practice; however, flexibility is provided by allowing the RC(s) and RAS-entity(ies) to
negotiate a mutually agreed upon schedule for the review.
Note: An RC may need to include this task in its reliability plan(s) for the NERC Regions(s)
in which it is located.
R2.
Each Reliability Coordinator that receives Attachment 1 information pursuant to
Requirement R1 shall, within four full calendar months of receipt or on a mutually
agreed upon schedule, perform a review of the RAS in accordance with Attachment 2,
and provide written feedback to each RAS-entity. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M2. Acceptable evidence may include, but is not limited to, dated reports, checklists, or
other documentation detailing the RAS review, and the dated communications with
the RAS-entity in accordance with Requirement R2.
Rationale for Requirement R3: The RC review is intended to identify reliability issues
that must be resolved before the RAS can be put in- service. Examples of reliability issues
include a lack of dependability, security, or coordination.
A specific time period for the RAS-entity to respond to the reviewing RC following
identification of any reliability issue(s) is not necessary because the RAS-entity wants to
expedite the timely approval and subsequent implementation of the RAS.
A specific time period for the RC to respond to the RAS-entity following the RAS review is
also not necessary because the RC will be aware of (1) any reliability issues associated
with the RAS not being in service and (2) the RAS-entity’s schedule to implement the RAS
to address those reliability issues. Since the RC is the ultimate arbiter of BES operating
reliability, resolving reliability issues is a priority for the RC and serves as an incentive to
expeditiously respond to the RAS-entity.
R3.
Prior to placing a new or functionally modified RAS in- service or retiring an existing
RAS, each RAS‐entity that receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve each issue to obtain
approval of the RAS from each reviewing Reliability Coordinator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
M3. Acceptable evidence may include, but is not limited to, dated documentation and
communications with the reviewing Reliability Coordinator that no reliability issues
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were identified during the review or that all identified reliability issues were resolved
in accordance with Requirement R3.
Rationale for Requirement R4: Requirement R4 mandates that an evaluation of each RAS
be performed at least once every five full calendar years. The purpose of the periodic RAS
evaluation is to verify the continued effectiveness and coordination of the RAS, as well as
to verify that, if a RAS single component malfunction or single component failure were to
occur, the requirements for BES performance would continue to be satisfied. A periodic
evaluation is required because changes in System topology or operating conditions may
change the effectiveness of a RAS or the way it impacts the BES.
RAS are unique and customized assemblages of protection and control equipment that
vary in complexity and impact on the reliability of the BES. In recognition of these
differences, RAS can be designated by the reviewing RC(s) as limited impact. A limited
impact RAS cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations. The “BES” qualifier in the preceding
statement modifies all of the conditions that follow it. Limited impact RAS are not subject
to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to
the design with minimal benefit to BES reliability. See the Supplemental Material for
more on the limited impact designation.
The limited impact designation is modeled afterThe standard recognizes the Local Area
Protection Scheme (LAPS) classification in WECC (Western Electricity Coordinating
Council) and the Type 3III classification in NPCC (Northeast Power Coordinating Council).)
as initially appropriate for limited impact designation. A RAS implemented prior to the
effective date of PRC-012-2 that has been through the regional review processes of WECC
or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC or a
Type 3III in NPCC is recognized as a limited impact RAS upon the effective date of PRC012-2 for the purposes of this standard and is subject to all applicable requirements.
For existing RAS, the initial performance of Requirement R4 must be completed within
five full calendar years of the effective date of PRC‐012‐2. For new or functionally
modified RAS, the initial performance of the requirement must be completed within five
full calendar years of the RAS approval date by the reviewing RC(s). Five full calendar
years was selected as the maximum time frame between evaluations based on the time
frames for similar requirements in Reliability Standards PRC-006, PRC-010, and PRC-014.
The RAS evaluation can be performed sooner if it is determined that material changes to
System topology or System operating conditions could potentially impact the
effectiveness or coordination of the RAS. System changes also have the potential to alter
the reliability impact of limited impact RAS on the BES. Requirement 4, Part 4.1.3
explicitly requires the periodic evaluation of limited impact RAS to verify the limited
impact designation remains applicable.; the PC can use its discretion as to how this
evaluation is performed. The periodic RAS evaluation will typically lead to one of the
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following outcomes: 1) affirmation that the existing RAS is effective; 2) identification of
changes needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1
through 4.1.5) are planning analyses that may involve modeling of the interconnected
transmission system to assess BES performance. The Planning Coordinator (PC) is the
functional entity best suited to perform this evaluation because they have a wide area
planning perspective. To promote reliability, the PC is required to provide the results of
the evaluation to each impacted Transmission Planner and Planning Coordinator, in
addition to each reviewing RC and RAS-entity. In cases where a RAS crosses PC
boundaries, each affected PC is responsible for conducting either individual evaluations
or participating in a coordinated evaluation.
The previous version of this standard (PRC-012-1 Requirement 1, R1.4) states “… the
inadvertent operation of a RAS shall meet the same performance requirement (TPL-0010, TPL-002-0, and TPL-003-0) as that required of the Contingency for which it was
designed, and not exceed TPL-003-0.” Requirement R4 clarifies that the inadvertent
operation to be considered would only be that caused by the malfunction of a single RAS
component. This allows security features to be designed into the RAS such that
inadvertent operation due to a single component malfunction is prevented. Otherwise,
consistent with PRC-012-1 Requirement 1, R1.4, the RAS should be designed so that its
whole or partial inadvertent operation due to a single component malfunction satisfies
the System performance requirements for the same Contingency for which the RAS was
designed.
If the RAS was installed for an extreme event in TPL-001-4 or for some other Contingency
or System condition not defined in TPL-001-4 (therefore without performance
requirements), its inadvertent operation still must meet some minimum System
performance requirements. However, instead of referring to the TPL-001-4, Requirement
R4 lists the System performance requirements that the inadvertent operation must
satisfy. The performance requirements listed (Parts 4.1.34.1 – 4.1.34.5) are the ones that
are common to all planning events P0-P7 listed in TPL-001-4.
R4.
Each Planning Coordinator, at least once every five full calendar years, shall:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
4.1. Perform an evaluation of each RAS within its planning area to determine
whether:
4.1.1. The RAS mitigates the System condition(s) or Contingency(ies) for which
it was designed.
4.1.2. The RAS avoids adverse interactions with other RAS, and protection and
control systems.
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4.1.3. For limited impact 1 RAS, the inadvertent operation of the RAS or the
failure of the RAS to operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations.
4.1.4. Except for limited impact RAS, the possible inadvertent operation of the
RAS, resulting from any single RAS component malfunction satisfies all of
the following:
4.1.4.1.
The BES shall remain stable.
4.1.4.2.
Cascading shall not occur.
4.1.4.3.
Applicable Facility Ratings shall not be exceeded.
4.1.4.4.
BES voltages shall be within post-Contingency voltage limits
and post-Contingency voltage deviation limits as established
by the Transmission Planner and the Planning Coordinator.
4.1.4.5.
Transient voltage responses shall be within acceptable limits
as established by the Transmission Planner and the Planning
Coordinator.
4.1.5. Except for limited impact RAS, a single component failure in the RAS,
when the RAS is intended to operate does not prevent the BES from
meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and
conditions for which the RAS is designed.
4.2. Provide the results of the RAS evaluation including any identified deficiencies to
each reviewing Reliability Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
M4. Acceptable evidence may include, but is not limited to, dated reports or other
documentation of the analyses comprising the evaluation(s) of each RAS and dated
communications with the RAS-entity(ies), Transmission Planner(s), Planning
Coordinator(s), and the reviewing Reliability Coordinator(s) in accordance with
Requirement R4.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
1
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Rationale for Requirement R5: The correct operation of a RAS is important for
maintaining the reliability and integrity of the BES. Any incorrect operation of a RAS
indicates that the RAS effectiveness and/or coordination has been compromised.
Therefore, all operations of a RAS and failures of a RAS to operate when expected must
be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: 1) verify RAS operation was
consistent with the implemented design; or 2) identify RAS performance deficiencies that
manifested in the incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC-004-4
regarding the investigation of a Protection System Misoperation. To promote reliability,
each RAS-entity is required to provide the results of RAS operational performance
analyses that identified any deficiencies to its reviewing RC(s).
RAS-entities may need to collaborate with their associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly
(Part 5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response
(Parts 5.1.3 and 5.1.4) was consistent with the intended functionality and design of the
RAS. Ideally, when there is more than one RAS-entity for a RAS, the RAS-entities would
collaborate to conduct and submit a single, coordinated operational performance
analysis.
R5.
Each RAS-entity, within 120 full calendar days of a RAS operation or a failure of its RAS
to operate when expected, or on a mutually agreed upon schedule with its reviewing
Reliability Coordinator(s), shall: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
5.1. Participate in analyzing the RAS operational performance to determine whether:
5.1.1. The System events and/or conditions appropriately triggered the RAS.
5.1.2. The RAS responded as designed.
5.1.3. The RAS was effective in mitigating BES performance issues it was
designed to address.
5.1.4. The RAS operation resulted in any unintended or adverse BES response.
5.2. Provide the results of RAS operational performance analysis that identified any
deficiencies to its reviewing Reliability Coordinator(s).
M5. Acceptable evidence may include, but is not limited to, dated documentation detailing
the results of the RAS operational performance analysis and dated communications
with participating RAS-entities and the reviewing Reliability Coordinator(s) in
accordance with Requirement R5.
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Rationale for Requirement R6: Deficiencies identified in the periodic RAS evaluation
conducted by the PC pursuant to Requirement R4, in the operational performance
analysis conducted by the RAS-entity pursuant to Requirement R5, or in the functional
test performed by the RAS-entity pursuant to Requirement R8, potentially pose a
reliability risk to the BES. To mitigate these potential reliability risks, Requirement R6
mandates that each RAS-entity develop a Corrective Action Plan (CAP) to address the
identified deficiency. The CAP contains the mitigation actions and associated timetable
necessary to remedy the specific deficiency. The RAS-entity may request assistance with
CAP development from other parties such as its Transmission Planner or Planning
Coordinator; however, the RAS-entity has the responsibility for compliance with this
requirement.
If the CAP requires that a functional change be made to a RAS, the RAS-entity will need to
submit information identified in Attachment 1 to the reviewing RC(s) prior to placing RAS
modifications in- service per Requirement R1.
Depending on the complexity of the identified deficiency(ies), development of a CAP may
require studies, and other engineering or consulting work. A maximum time frame of six
full calendar months is specified for RAS-entity collaboration on the CAP development.
Ideally, when there is more than one RAS-entity for a RAS, the RAS-entities would
collaborate to develop and submit a single, coordinated CAP.
R6.
Each RAS-entity shall participate in developing a Corrective Action Plan (CAP) and
submit the CAP to its reviewing Reliability Coordinator(s) within six full calendar
months of: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Longterm Planning]
•
Being notified of a deficiency in its RAS pursuant to Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency pursuant to Requirement R5,
Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to Requirement R8.
M6. Acceptable evidence may include, but is not limited to, a dated CAP and dated
communications among each reviewing Reliability Coordinator and each RAS-entity in
accordance with Requirement R6.
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Rationale for Requirement R7: Requirement R7 mandates each RAS-entity implement a
CAP (developed in Requirement R6) that mitigates the deficiencies identified in
Requirements R4, R5, or R8. By definition, a CAP is: “A list of actions and an associated
timetable for implementation to remedy a specific problem.” The implementation of a
properly developed CAP ensures that RAS deficiencies are mitigated in a timely manner.
Each reviewing Reliability Coordinator must be notified if CAP actions or timetables
change, and when the CAP is completed.
R7.
Each RAS-entity shall, for each of its CAPs developed pursuant to Requirement R6:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Long-term
Planning]
7.1. Implement the CAP.
7.2. Update the CAP if actions or timetables change.
7.3. Notify each reviewing Reliability Coordinator if CAP actions or timetables change
and when the CAP is completed.
M7. Acceptable evidence may include, but is not limited to, dated documentation such as
CAPs, project or work management program records, settings sheets, work orders,
maintenance records, and communication with the reviewing Reliability
Coordinator(s) that documents the implementation, updating, or completion of a CAP
in accordance with Requirement R7.
Rationale for Requirement R8: Due to the wide variety of RAS designs and
implementations, and the potential for impacting BES reliability, it is important that
periodic functional testing of a RAS be performed. A functional test provides an overall
confirmation of the RAS to operate as designed and verifies the proper operation of the
non-Protection System (control) components of a RAS that are not addressed in PRC-005.
Protection System components that are part of a RAS are maintained in accordance with
PRC-005.
The six or twelve full calendar year test interval, which begins on the effective date of the
standard pursuant to the PRC-012-2 implementation plan, is a balance between the
resources required to perform the testing and the potential reliability impacts to the BES
created by undiscovered latent failures that could cause an incorrect operation of the
RAS. Extending to longer intervals increases the reliability risk to the BES posed by an
undiscovered latent failure that could cause an incorrect operation or failure of the RAS.
The RAS-entity is in the best position to determine the testing procedure and schedule
due to its overall knowledge of the RAS design, installation, and functionality. Functional
testing may be accomplished with end-to-end testing or a segmented approach. For
segmented testing, each segment of a RAS must be tested. Overlapping segments can be
tested individually negating the need for complex maintenance schedules and outages.
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The maximum allowable interval between functional tests is six full calendar years for RAS
that are not designated as limited impact RAS and twelve full calendar years for RAS that
are designated as limited impact RAS. The interval between tests begins on the date of
the most recent successful test for each individual segment or end-to-end test. A
successful test of one segment only resets the test interval clock for that segment. A
correct operation of a RAS qualifies as a functional test for those RAS segments which
operate (documentation for compliance with Requirement R5 Part 5.1). If an event causes
a partial operation of a RAS, the segments without an operation will require a separate
functional test within the maximum interval with the starting date determined by the
previous successful test of the segments that did not operate.
R8.
Each RAS-entity shall participate in performing a functional test of each of its RAS to
verify the overall RAS performance and the proper operation of non-Protection
System components: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
•
At least once every six full calendar years for all RAS not designated as limited
impact, or
•
At least once every twelve full calendar years for all RAS designated as limited
impact
M8. Acceptable evidence may include, but is not limited to, dated documentation detailing
the RAS operational performance analysis for a correct RAS segment or an end-to-end
operation (Measure M5 documentation), or dated documentation demonstrating that
a functional test of each RAS segment or an end-to-end test was performed in
accordance with Requirement R8.
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PRC-012-2 – Remedial Action Schemes
Rationale for Requirement R9: The RAS database is a comprehensive record of all RAS
existing in a Reliability Coordinator Area. The database enables the RC to provide other
entities high-level information on existing RAS that could potentially impact the
operational and/or planning activities of that entity. Attachment 3 lists the minimum
information required for the RAS database, which includes a summary of the RAS
initiating conditions, corrective actions, and System issues being mitigated. This
information allows an entity to evaluate the reliability need for requesting more detailed
information from the RAS-entities identified in the database contact information. The RC
is the appropriate entity to maintain the database because the RC receives the required
database information when a new or modified RAS is submitted for review. The twelve
full calendar month time frame is aligned with industry practice and allows sufficient time
for the RC to collect the appropriate information from RAS-entities and update the RAS
database.
R9.
Each Reliability Coordinator shall update a RAS database containing, at a minimum,
the information in Attachment 3 at least once every twelve full calendar months.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
M9. Acceptable evidence may include, but is not limited to, dated spreadsheets, database
reports, or other documentation demonstrating a RAS database was updated in
accordance with Requirement R9.
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2.
Evidence Retention:
The following evidence retention period(s) identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The RAS-entity (Transmission Owner, Generator Owner, and Distribution
Provider) shall each keep data or evidence to show compliance with
Requirements R1, R3, R5, R6, R7, and R8, and Measures M1, M3, M5, M6, M7,
and M8 since the last audit, unless directed by its Compliance Enforcement
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FebruaryApril 2016
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PRC-012-2 – Remedial Action Schemes
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Reliability Coordinator shall each keep data or evidence to show compliance
with Requirements R2 and R9, and Measures M2 and M9 since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
The Planning Coordinator shall each keep data or evidence to show compliance
with Requirement R4 and Measure M4 since the last audit, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period
of time as part of an investigation.
If a RAS-entity (Transmission Owner, Generator Owner or Distribution Provider),
Reliability Coordinator, or Planning Coordinator is found non-compliant, it shall
keep information related to the non-compliance until mitigation is completed and
approved, or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated Reliability Standard.
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FebruaryApril 2016
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PRC-012-2 – Remedial Action Schemes
Violation Severity Levels
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
The RAS-entity failed to
provide the information
identified in Attachment 1 to
each Reliability Coordinator
prior to placing a new or
functionally modified RAS inservice or retiring an existing
RAS in accordance with
Requirement R1.
R2.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by less than or equal to
30 full calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The reviewing Reliability
Coordinator performed the
review and provided the
written feedback in
accordance with
Requirement R2, but was
late by more than 90 full
calendar days.
Draft 3 of PRC-012-2
FebruaryApril 2016
OR
The reviewing Reliability
Coordinator failed to
perform the review or
provide feedback in
accordance with
Requirement R2.
Page 14 of 53
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
N/A
N/A
N/A
The RAS-entity failed to
resolve identified reliability
issue(s) to obtain approval
from each reviewing
Reliability Coordinator prior
to placing a new or
functionally modified RAS inservice or retiring an existing
RAS in accordance with
Requirement R3.
R4.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but was
late by more than 90 full
calendar days.
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate one of the Parts
4.1.1 through 4.1.5.
Draft 3 of PRC-012-2
FebruaryApril 2016
OR
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to evaluate two or more of
the Parts 4.1.1 through 4.1.5.
OR
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PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Planning Coordinator
performed the evaluation in
accordance with
Requirement R4, but failed
to provide the results to one
or more of the receiving
entities listed in Part 4.2.
OR
The Planning Coordinator
failed to perform the
evaluation in accordance
with Requirement R4.
R5.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by less than or
equal to 10 full calendar
days.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to address one of the
Parts 5.1.1 through 5.1.4.
Draft 3 of PRC-012-2
FebruaryApril 2016
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
was late by more than 30 full
calendar days.
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to address two or
more of the Parts 5.1.1
through 5.1.4.
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PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
The RAS-entity performed
the analysis in accordance
with Requirement R5, but
failed to provide the results
(Part 5.2) to one or more of
the reviewing Reliability
Coordinator(s).
OR
The RAS-entity failed to
perform the analysis in
accordance with
Requirement R5.
R6.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by less than or equal to
10 full calendar days.
Draft 3 of PRC-012-2
FebruaryApril 2016
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 10 full
calendar days but less than
or equal to 20 full calendar
days.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 20 full
calendar days but less than
or equal to 30 full calendar
days.
The RAS-entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6, but was
late by more than 30 full
calendar days.
OR
The RAS-entity developed a
Corrective Action Plan but
failed to submit it to one or
Page 17 of 53
PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
more of its reviewing
Reliability Coordinator(s) in
accordance with
Requirement R6.
OR
The RAS-entity failed to
develop a Corrective Action
Plan in accordance with
Requirement R6.
R7.
The RAS-entity implemented N/A
a CAP in accordance with
Requirement R7, Part 7.1,
but failed to update the CAP
(Part 7.2) if actions or
timetables changed, or failed
to notify (Part 7.3) each of
the reviewing Reliability
Coordinator(s) of the
updated CAP or completion
of the CAP.
N/A
The RAS-entity failed to
implement a CAP in
accordance with
Requirement R7, Part 7.1.
R8.
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by less than
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 60 full calendar days
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 90 full calendar days.
Draft 3 of PRC-012-2
FebruaryApril 2016
The RAS-entity performed
the functional test for a RAS
as specified in Requirement
R8, but was late by more
than 30 full calendar days
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PRC-012-2 – Remedial Action Schemes
R#
Violation Severity Levels
Lower VSL
R9.
Moderate VSL
High VSL
or equal to 30 full calendar
days.
but less than or equal to 60
full calendar days.
but less than or equal to 90
full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by less than or equal to
30 full calendar days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 30 full
calendar days but less than
or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9, but was
late by more than 60 full
calendar days but less than
or equal to 90 full calendar
days.
Draft 3 of PRC-012-2
FebruaryApril 2016
Severe VSL
OR
The RAS-entity failed to
perform the functional test
for a RAS as specified in
Requirement R8.
The Reliability Coordinator
updated the RAS database in
accordance with
Requirement R9 but was late
by more than 90 full
calendar days.
OR
The Reliability Coordinator
failed to update the RAS
database in accordance with
Requirement R9.
Page 19 of 53
PRC-012-2 – Remedial Action Schemes
D. Regional Variances
None.
E. Associated Documents
Version History
Version
0
Date
1
Draft 3 of PRC-012-2
FebruaryApril 2016
Change Tracking
February 8, 2005 Adopted by the Board of Trustees Reliability
Standard PRC-012-0 was adopted by the Board of
Trustees.
March 16, 2007
Identified by Commission as “fill-in-the-blank” with
no action taken on the standard Commission
identified PRC-012-0 as a “fill-in-the-blank”
standard and did not approve or remand the
standard
November 13,
2014
Adopted by the Board of Trustees Revised
definition of Remedial Action Scheme and several
associated revised Reliability Standards, including
PRC-012-1, were adopted by the Board of Trustees
November 19,
2015
Accepted by Commission for informational
purposes only Commission approved revised
definition of Remedial Action Scheme and
accepted PRC-012-1 for informational purposes
only
0
1
Action
Page 20 of 53
PRC-012-2 – Remedial Action Schemes
Adopted by Board of TrusteesAdopted by Board of
Trustees
2
Version
1
Draft 3 of PRC-012-2
FebruaryApril 2016
Date
New
Action
Adopted by NERC Board of Trustees
Change Tracking
New
Page 21 of 53
Attachments
Attachment 1
Supporting Documentation for RAS Review
The following checklist identifies important Remedial Action Scheme (RAS) information for
each new or functionally modified 2 RAS that the RAS-entity must document and provide to
the reviewing Reliability Coordinator(s) (RC). If an item on this list does not apply to a
specific RAS, a response of “Not Applicable” for that item is appropriate. When RAS are
submitted for functional modification review and approval, only the proposed modifications
to that RAS require review; however, the RAS-entity must provide a summary of the existing
functionality. The RC may request additional information on any aspect of the RAS as well as
any reliability issue related to the RAS. Additional entities (without decision authority) may
be part of the RAS review process at the request of the RC.
I. General
1. Information such as maps, one-line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre- and post-modified functionality of the RAS.
3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
4. Data to populate the RAS database:
a. RAS name.
b. Each RAS-entity and contact information.
c. Expected or actual in-service date; most recent RC-approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under- or overvoltage, or slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (i.e., initiating conditions).
f. Action(s) to be taken by the RAS.
2
Functionally Mmodified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
Draft 3 of PRC-012-2
FebruaryApril 2016
Page 22 of 53
Attachments
g. Identification of limited impact 3 RAS.
h. Any additional explanation relevant to high-level understanding of the RAS.
II.
Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
2. The action(s) to be taken by the RAS in response to disturbance conditions.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed.
4. Information regarding any future System plans that will impact the RAS.
5. RAS-entity proposal and justification for limited impact designation, if applicable.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoid adverse interactions
with other RAS, and protection and control systems.
8. Identification of other affected RCs.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
3
Draft 3 of PRC-012-2
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Page 23 of 53
Attachments
III. Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
2. Information on detection logic and settings/parameters that control the operation of
the RAS.
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in- service or is being
maintained.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective.
5. Documentation describing the functional testing process.
IV. RAS Retirement
The following checklist identifies RAS information that the RAS-entity shall document and
provide to each reviewing RC.
1. Information necessary to ensure that the RC is able to understand the physical and
electrical location of the RAS and related facilities.
2. A summary of applicable technical studies and technical justifications upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
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Attachments
Attachment 2
Reliability Coordinator RAS Review Checklist
The following checklist identifies reliability-related considerations for the Reliability Coordinator
(RC) to review and verify for each new or functionally modified 4 Remedial Action Scheme (RAS).
The RC review is not limited to the checklist items and the RC may request additional
information on any aspect of the RAS as well as any reliability issue related to the RAS. If a
checklist item is not relevant to a particular RAS, it should be noted as “Not Applicable.” If
reliability considerations are identified during the review, the considerations and the proposed
resolutions should be documented with the remaining applicable Attachment 2 items.
I.
Design
1. The RAS actions satisfy performance objectives for the scope of events and conditions
that the RAS is intended to mitigate.
2. The designed timing of RAS operation(s) is appropriate to its BES performance
objectives.
3. The RAS arming conditions, if applicable, are appropriate to its System performance
objectives.
4. The RAS avoids adverse interactions with other RAS, and protection and control
systems.
5. The effects of RAS incorrect operation, including inadvertent operation and failure to
operate, have been identified.
6. Determination whether or not the RAS is limited impact. 5 A RAS designated as limited
impact cannot, by inadvertent operation or failure to operate, cause or contribute to
BES Cascading, uncontrolled separation, angular instability, voltage instability, voltage
collapse, or unacceptably damped oscillations.
7. Except for limited impact RAS as determined by the RC, the possible inadvertent
operation of the RAS resulting from any single RAS component malfunction satisfies all
of the following:
a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
Functionally Mmodified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
5 A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
4
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Attachments
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
8. The effects of future BES modifications on the design and operation of the RAS have
been identified, where applicable.
II. Implementation
1. The implementation of RAS logic appropriately correlates desired actions (outputs) with
events and conditions (inputs).
2. Except for limited impact RAS as determined by the RC, a single component failure in a
RAS does not prevent the BES from meeting the same performance requirements as
those required for the events and conditions for which the RAS is designed.
3. The RAS design facilitates periodic testing and maintenance.
4. The mechanism or procedure by which the RAS is armed is clearly described, and is
appropriate for reliable arming and operation of the RAS for the conditions and events
for which it is designed to operate.
III. RAS Retirement
RAS retirement reviews should assure that there is adequate justification for why a RAS is
no longer needed.
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Attachments
Attachment 3
Database Information
1. RAS name.
2. Each RAS-entity and contact information.
3. Expected or actual in-service date; most recent RC-approval date (Requirement R3);
most recent evaluation date (Requirement R4); and date of retirement, if applicable.
4. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under- or over-voltage,
or slow voltage recovery).
5. Description of the Contingencies or System conditions for which the RAS was designed
(i.e., initiating conditions).
6. Action(s) to be taken by the RAS.
7. Identification of limited impact 6 RAS.
8. Any additional explanation relevant to high-level understanding of the RAS.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
6
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Supplemental Material
Technical Justification
4.1.1 Reliability Coordinator
The Reliability Coordinator (RC) is the best-suited functional entity to perform the Remedial
Action Scheme (RAS) review because the RC has the widest- area reliability perspective of all
functional entities and an awareness of reliability issues in neighboring RC Areas. The WideArea purview better facilitates the evaluation of interactions among separate RAS, as well as
interactions among RAS and other protection and control systems. The selection of the RC also
minimizes the possibility of a conflict of interest that could exist because of business
relationships among the RAS-entity, Planning Coordinator, Transmission Planner, or other
entities involved in the planning or implementation of a RAS. The RC is also less likely to be a
stakeholder in any given RAS and can therefore maintain objective independence.
4.1.2 Planning Coordinator
The Planning Coordinator (PC) is the best-suited functional entity to perform the RAS evaluation
to verify the continued effectiveness and coordination of the RAS, its inadvertent operation
performance, and the performance for a single component failure. The items that must be
addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
4.1.3 RAS-entity
The RAS-entity is any Transmission Owner, Generator Owner, or Distribution Provider that
owns all or part of a RAS. If all of the RAS (RAS components) have a single owner, then that RASentity has sole responsibility for all the activities assigned within the standard to the RAS-entity.
If the RAS (RAS components) have more than one owner, then each separate RAS component
owner is a RAS-entity and is obligated to participate in various activities identified by the
Requirements.
The standard does not stipulate particular compliance methods. RAS-entities have the option of
collaborating to fulfill their responsibilities for each applicable requirement. Such collaboration
and coordination may promote efficiency in achieving the reliability objectives of the
requirements; however, the individual RAS-entity must be able to demonstrate its participation
for compliance. As an example, the individual RAS-entities could collaborate to produce and
submit a single, coordinated Attachment 1 to the reviewing RC pursuant to Requirement R1 to
initiate the RAS review process.
Limited impact
RAS are unique and customized assemblages of protection and control equipment that vary in
complexity and impact on the reliability of the BES. These differences in RAS design, action, and
risk to the BES are identified and verified within the construct of Requirements R1-R4 of PRC012-2.
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Supplemental Material
The reviewing RC has the authority to designate a RAS as limited impact if the RAS cannot, by
inadvertent operation or failure to operate, cause or contribute to BES Cascading, uncontrolled
separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations. The reviewing RC ismakes the sole arbiter for determiningfinal determination as to
whether a RAS qualifies for the limited impact designation. The limited impact designation is
available to any RAS in any Region based upon the studies and other information provided the
reviewing RC determineswith the RAS poses a low risk to BES reliabilityAttachment 1 submittal
by the RAS-entity.
The limited impact designation is modeled afterThe standard recognizes the Local Area
Protection Scheme (LAPS) classification in WECC (Western Electricity Coordinating Council) and
the Type 3III classification in NPCC (Northeast Power Coordinating Council).) as initially
appropriate for limited impact designation. The following information describing the
aforementioned WECC and NPCC RAS is excerpted from the respective regional
documentation 7.The drafting team notes that the information below represents the state of
the WECC and NPCC regional processes at the time of this standard development and is subject
to change before the effective date of PRC-012-2.
WECC: Local Area Protection Scheme (LAPS)
A Remedial Action Scheme (RAS) whose failure to operate would NOT result in any of the
following:
•
Violations of TPL-001-WECC-RBP System Performance RBP,
•
Maximum load loss ≥ 300 MW,
•
Maximum generation loss ≥ 1000 MW.
NPCC: Type III
An SPS whose misoperation or failure to operate results in no significant adverse impact
outside the local area.
The following terms are also defined by NPCC to assess the impact of the SPS for
classification:
Significant adverse impact – With due regard for the maximum operating capability of the
affected systems, one or more of the following conditions arising from faults or disturbances,
shall be deemed as having significant adverse impact:
a. system instability;
b. unacceptable system dynamic response or equipment tripping;
c. voltage levels in violation of applicable emergency limits;
d. loadings on transmission facilities in violation of applicable emergency limits;
WECC Procedure to Submit a RAS for Assessment Information Required to Assess the Reliability of a RAS Guideline, Revised
10/28/2013 | NPCC Regional Reliability Reference Directory # 7, Special Protection Systems, Version 2, 3/31/2015
7
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Supplemental Material
e. unacceptable loss of load.
Local area – An electrically confined or radial portion of the system. The geographic size and
number of system elements contained will vary based on system characteristics. A local area
may be relatively large geographically with relatively few buses in a sparse system, or be
relatively small geographically with a relatively large number of buses in a densely networked
system.
Because the drafting team modeled the limited impact designation after the WECC and NPCC
classifications, eachA RAS implemented prior to the effective date of PRC-012-2 that has been
through the regional review processes of WECC or NPCC and classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3III in NPCC, is recognized as a limited impact RAS
upon the effective date of PRC-012-2 for the purposes of this standard and is subject to all
applicable requirements.
To propose an existing RAS (a RAS implemented prior to the effective date of PRC-012-2) be
designated as limited impact by the reviewing RC, the RAS-entity must prepare and submit the
appropriate Attachment 1 information that includes the technical justification (evaluations)
documenting that the System can meet the performance requirements (specified in
Requirement R4, Parts 4.1.4 and 4.1.5) resulting from a single RAS component malfunction or
failure, respectively.
There is nothing that precludes a RAS-entity from working with the reviewing RC during the
implementation period of PRC-012-2, in anticipation of the standard becoming enforceable.
However, even if the reviewing RC determines the RAS qualifies as limited impact, the
designation is not relevant until the standard becomes effective. Until then, the existing
regional processes remain in effect as well as the existing RAS classifications or lack thereof.
An example of a scheme that could be recognized as a limited impact RAS is a load shedding or
generation rejection scheme used to mitigate the overload of a BES transmission line. The
inadvertent operation of such a scheme would cause the loss of either a certain amount of
generation or load. The evaluation by the RAS-entity should demonstrate that the loss of this
amount of generation or load, without the associated contingency for RAS operation actually
occurring, is acceptable and not detrimental to the reliability of BES; e.g., in terms of frequency
and voltage stability. The failure of that scheme to operate when intended could potentially
lead to the overloading of a transmission line beyond its acceptable rating. The RAS-entity
would need to demonstrate that this overload, while in excess of the applicable Facility Rating,
is not detrimental to the BES outside the contained area (predetermined by studies) affected by
the contingency.
Another exampleOther examples of a limited- impact RAS is ainclude:
•
A scheme used to protect BES equipment from damage caused by overvoltage through
generation rejection or equipment tripping.
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Supplemental Material
•
Another example of a limited-impact RAS is aA centrally-controlled undervoltage load
shedding scheme used to protect a contained area (predetermined by studies) of the
BES against voltage collapse.
•
A scheme used to trip a generating unit following certain BES Contingencies to prevent
the unit from going out of synch with the System; where, if the RAS fails to operate and
the unit pulls out of synchronism, the resulting apparent impedance swings do not
result in the tripping of any Transmission System Elements other than the generating
unit and its directly connected Facilities.
Requirement R1
Each RAS is unique and its action(s) can have a significant impact on the reliability and integrity
of the Bulk Electric System (BES); therefore, a review of a proposed new RAS or an existing RAS
proposed for functional modification, or retirement (removal from service) must be completed
prior to implementation.
Functional modifications consists of any of the following:
•
Changes to System conditions or Contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original
functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
An example indicating the limits of an in-kind replacement of a RAS component is the
replacement of one relay (or other device) with a relay (or other device) that uses similar
functions. For instance, if a RAS included a CO-11 relay which was replaced by an IAC-53 relay,
that would be an in-kind replacement. If the CO-11 relay were replaced by a microprocessor
SEL-451 relay that used only the same functions as the original CO-11 relay, that would also be
an in-kind replacement; however, if the SEL-451 relay was used to add new logic to what the
CO-11 relay had provided, then the replacement relay would be a functional modification.
Changes to RAS pickup levels that require no other scheme changes are not considered a
functional modification. For example, System conditions require a RAS to be armed when the
combined flow on two lines exceeds 500 MW. If a periodic evaluation pursuant to Requirement
R4, or other assessment, indicates that the arming level should be reduced to 450 MW without
requiring any other RAS changes that would not be a functional modification. Similarly, if a RAS
is designed to shed load to reduce loading on a particular line below 1000 amps, then a change
in the load shedding trigger from 1000 amps to 1100 amps would not be a functional
modification.
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Supplemental Material
Another example illustrates a case where a System change may result in a RAS functional
change. Assume that a generation center is connected to a load center through two
transmission lines. The lines are not rated to accommodate full plant output if one line is out of
service, so a RAS monitors the status of both lines and trips or ramps down the generation to a
safe level following loss of either line. Later, one of the lines is tapped to serve additional load.
The System that the RAS impacts now includes three lines, loss of any of which is likely to still
require generation reduction. The modified RAS will need to monitor all three lines (add two
line terminal status inputs to the RAS) and the logic to recognize the specific line outages would
change, while the generation reduction (RAS output) requirement may or may not change,
depending on which line is out of service. These required RAS changes would be a functional
modification.
Any functional modification to a RAS will need to be reviewed and approved through the
process described in Requirements R1, R2, and R3. The need for such functional modifications
may be identified in several ways including but not limited to the Planning evaluations pursuant
to R4, incorrect operations pursuant to R5, a test failure pursuant to R8, or Planning
assessments related to future additions or modifications of other facilities.
See Item 4a in the Implementation Section of Attachment 1 in the Supplemental Material
section for typical RAS components for which a failure may be considered. The RC has the
discretion to make the final determination regarding which components should be regarded as
RAS components during its review.
To facilitate a review that promotes reliability, the RAS-entity(ies) must provide the reviewer
with sufficient details of the RAS design, function, and operation. This data and supporting
documentation are identified in Attachment 1 of this standard, and Requirement R1 mandates
that the RAS-entity(ies) provide them to the reviewing Reliability Coordinator (RC). The RC that
coordinates the area where the RAS is located is responsible for the review. In cases where a
RAS crosses multiple RC Area boundaries, each affected RC is responsible for conducting either
individual reviews or a coordinated review.
Requirement R1 does not specify how far in advance of implementation the RAS-entity(ies)
must provide Attachment 1 data to the reviewing RC. The information will need to be
submitted early enough to allow RC review in the allotted time pursuant to Requirement R2,
including resolution of any reliability issues that might be identified, in order to obtain approval
of the reviewing RC. Expeditious submittal of this information is in the interest of each RASentity to effect a timely implementation.
Requirement R2
Requirement R2 mandates that the RC perform reviews of all proposed new RAS and existing
RAS proposed for functional modification, or retirement (removal from service) in its RC Area.
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Supplemental Material
RAS are unique and customized assemblages of protection and control equipment. As such,
they have a potential to introduce reliability risks to the BES, if not carefully planned, designed,
and installed. A RAS may be installed to address a reliability issue, or achieve an economic or
operational advantage, and could introduce reliability risks that might not be apparent to a
RAS-entity(ies). An independent review by a multi-disciplinary panel of subject matter experts
with planning, operations, protection, telecommunications, and equipment expertise is an
effective means of identifying risks and recommending RAS modifications when necessary.
The RC is the functional entity best suited to perform the RAS reviews because it has the
widest- area reliability perspective of all functional entities and an awareness of reliability
issues in neighboring RC Areas. This Wide Area purview facilitates the evaluation of interactions
among separate RAS as well as interactions among the RAS and other protection and control
systems.
The selection of the RC also minimizes the possibility of a “conflict of interest” that could exist
because of business relationships among the RAS-entity, Planning Coordinator (PC),
Transmission Planner (TP), or other entities that are likely to be involved in the planning or
implementation of a RAS. The RC may request assistance in RAS reviews from other parties
such as the PC(s) or regional technical groups (e.g., Regional Entities); however, the RC retains
responsibility for compliance with the requirement. It is recognized that the RC does not
possesses more information or ability than anticipated by their functional registration as
designated by NERC. The NERC Functional Model is a guideline for the development of
standards and their applicability and does not contain compliance requirements. If Reliability
Standards address functions that are not described in the model, the Reliability Standard
requirements take precedence over the Functional Model. For further reference, please see the
Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
Attachment 2 of this standard is a checklist for assisting the RC in identifying design and
implementation aspects of a RAS, and for facilitating consistent reviews of each RAS submitted
for review. The time frame of four full calendar months is consistent with current utility
practice; however, flexibility is provided by allowing the parties to negotiate a different
schedule for the review. Note, an RC may need to include this task in its reliability plan(s) for
the NERC Region(s) in which it is located.
Requirement R3
Requirement R3 mandates that each RAS-entity resolve all reliability issues (pertaining to its
RAS) identified during the RAS review by the reviewing Reliability Coordinators. Examples of
reliability issues include a lack of dependability, security, or coordination. RC approval of a RAS
is considered to be obtained when the reviewing RC’s feedback to each RAS-entity indicates
that either no reliability issues were identified during the review or all identified reliability
issues were resolved to the RC’s satisfaction.
Dependability is a component of reliability that is the measure of certainty of a device to
operate when required. If a RAS is installed to meet performance requirements of NERC
Reliability Standards, a failure of the RAS to operate when intended would put the System at
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Supplemental Material
risk of violating NERC Reliability Standards if specified Contingency(ies) or System conditions
occur. This risk is mitigated by designing the RAS so that it will accomplish the intended purpose
while experiencing a single RAS component failure. This is often accomplished through
redundancy. Other strategies for providing dependability include “over-tripping” load or
generation, or alternative automatic backup schemes.
Security is a component of reliability that is the measure of certainty of a device to not operate
inadvertently. False or inadvertent operation of a RAS results in taking a programmed action
without the appropriate arming conditions, occurrence of specified Contingency(ies), or System
conditions expected to trigger the RAS action. Typical RAS actions include shedding load or
generation or re-configuring the System. Such actions, if inadvertently taken, are undesirable
and may put the System in a less secure state. Worst case impacts from inadvertent operation
often occur if all programmed RAS actions occur. If the System performance still satisfies PRC012-2 Requirement R4, Part 4.3, no additional mitigation is required. Security enhancements to
the RAS design, such as voting schemes, are acceptable mitigations against inadvertent
operations.
Any reliability issue identified during the review must be resolved before implementing the RAS
to avoid placing the System at unacceptable risk. The RAS-entity or the reviewing RC(s) may
have alternative ideas or methods available to resolve the issue(s). In either case, the concern
needs to be resolved in deference to reliability, and the RC has the final decision.
A specific time period for the RAS-entity to respond to the RC(s) review is not necessary
because an expeditious response is in the interest of each RAS-entity to effect a timely
implementation.
A specific time period for the RC to respond to the RAS-entity following the RAS review is also
not necessary because the RC will be aware of (1) any reliability issues associated with the RAS
not being in service and (2) the RAS-entity’s schedule to implement the RAS to address those
reliability issues. Since the RC is the ultimate arbiter of BES operating reliability, resolving
reliability issues is a priority for the RC and serves as an incentive to expeditiously respond to
the RAS-entity.
Requirement R4
Requirement R4 mandates that an evaluation of each RAS be performed at least once every five
full calendar years. The purpose of a periodic RAS evaluation is to verify the continued
effectiveness and coordination of the RAS, as well as to verify that requirements for BES
performance following inadvertent RAS operation and single component failure continue to be
satisfied. A periodic evaluation is required because changes in System topology or operating
conditions may change the effectiveness of a RAS or the way it interacts with and impacts the
BES.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate,
cause or contribute to BES Cascading, uncontrolled separation, angular instability, voltage
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Supplemental Material
instability, voltage collapse, or unacceptably damped oscillations. Limited impact RAS are not
subject to the RAS single component malfunction and failure tests of Parts 4.1.4 and 4.1.5,
respectively. Requiring a limited impact RAS to meet these tests would add complexity to the
design with minimal benefit to BES reliability.
A RAS implemented after the effective date of this standard can only be designated as limited
impact by the reviewing RC(s). A RAS implemented prior to the effective date of PRC-012-2 that
has been through the regional review processes of WECC or NPCC and is classified as either a
Local Area Protection Scheme (LAPS) in WECC or a Type 3III in NPCC is recognized as a limited
impact RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
Requirement R4 also clarifies that the RAS single component failure and inadvertent operation
tests do not apply to RAS which are determined to be limited impact. Requiring a limited impact
RAS to meet the single component failure and inadvertent operation tests would just add
complexity to the design with little or no improvement in the reliability of the BES.
For existing RAS, the initial performance of Requirement R4 must be completed within five full
calendar years of the effective date of PRC‐012‐2. For new or functionally modified RAS, the
initial performance of the requirement must be completed within five full calendar years of the
RAS approval date by the reviewing RC(s). Five full calendar years was selected as the maximum
time frame between evaluations based on the time frames for similar requirements in
Reliability Standards PRC-006, PRC-010, and PRC-014. The RAS evaluation can be performed
sooner if it is determined that material changes to System topology or System operating
conditions could potentially impact the effectiveness or coordination of the RAS. System
changes also have the potential to alter the reliability impact of limited impact RAS on the BES.
Requirement 4, Part 4.1.3 explicitly requires the periodic evaluation of limited impact RAS to
verify the limited impact designation remains applicable. The periodic RAS evaluation will
typically lead to one of the following outcomes: 1) affirmation that the existing RAS is effective;
2) identification of changes needed to the existing RAS; or, 3) justification for RAS retirement.
The items required to be addressed in the evaluations (Requirement R4, Parts 4.1.1 through
4.1.5) are planning analyses that may involve modeling of the interconnected transmission
system to assess BES performance. The PC is the functional entity best suited to perform the
analyses because they have a wide-area planning perspective. To promote reliability, the PC is
required to provide the results of the evaluation to each impacted Transmission Planner and
Planning Coordinator, in addition to each reviewing RC and RAS-entity. In cases where a RAS
crosses PC boundaries, each affected PC is responsible for conducting either individual
evaluations or participating in a coordinated evaluation.
The intent of Requirement R4, Part 4.1.4 is to requireverify that the possible inadvertent
operation of the RAS (other than limited impact RAS), caused by the malfunction of a single
component of the RAS, meet the same System performance requirements as those required for
the Contingency(ies) or System conditions for which it is designed. If the RAS is designed to
meet one of the planning events (P0-P7) in TPL-001-4, the possible inadvertent operation of the
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Supplemental Material
RAS must meet the same performance requirements listed in the standard for that planning
event. The requirement clarifies that the inadvertent operation to be considered is only that
caused by the malfunction of a single RAS component. This allows features to be designed into
the RAS to improve security, such that inadvertent operation due to malfunction of a single
component is prevented; otherwise, the RAS inadvertent operation must satisfy Requirement
R4, Part 4.1.4.
The intent of Requirement R4, Part 4.1.4 is also to requireverify that the possible inadvertent
operation of the RAS (other than limited impact RAS) installed for an extreme event in TPL-0014 or for some other Contingency or System conditions not defined in TPL-001-4 (therefore
without performance requirements), meet the minimum System performance requirements of
Category P7 in Table 1 of NERC Reliability Standard TPL-001-4. However, instead of referring to
the TPL standard, the requirement lists the System performance requirements that a potential
inadvertent operation must satisfy. The performance requirements listed (Requirement R4,
Parts 4.1.4.1 – 4.1.4.5) are the ones that are common to all planning events (P0-P7) listed in
TPL-001-4.
With reference to Requirement 4, Part 4.1.4, note that the only differences in performance
requirements among the TPL (P0-P7) events (not common to all of them) concern NonConsequential Load Loss and interruption of Firm Transmission Service. It is not necessary for
Requirement R4, Part 4.1.4 to specify performance requirements related to these areas
because a RAS is only allowed to drop non-consequential load or interrupt Firm Transmission
Service if that action is allowed for the Contingency for which it is designed. Therefore, the
inadvertent operation should automatically meet Non-Consequential Load Loss or interrupting
Firm Transmission Service performance requirements for the Contingency(ies) for which it was
designed.
The intent of Requirement R4, Part 4.1.5 requiresis to verify that a single component failure in
thea RAS (, other than limited impact RAS),, when the RAS is intended to operate, does not
prevent the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for which
the RAS is designed. This analysis is needed to ensure that changing System conditions do not
result in the single component failure requirement not being met.
The following is an example of a single component failure causing the System to fail to meet the
performance requirements for the P1 event for which the RAS was installed. Requirements for
inadvertent RAS operation (Requirement R4, Part 4.1.4) and single component failure
(Requirement R4, Part 4.1.5) are reviewed by the reviewing RC(s) before a new or functionally
modified RAS is placed in-service, and are typically satisfied by specific design considerations.
Although the scope of the periodic evaluation does not include a new design review, it is
possible that aConsider the instance where a three-phase Fault (P1 event) results in a
generating plant becoming unstable (a violation of the System performance requirements of
TPL-001-4). To resolve this, a RAS is installed to trip a single generating unit which allows the
remaining units at the plant to remain stable. If failure of a single component (e.g., relay) in the
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Supplemental Material
RAS results in the RAS failing to operate for the P1 event, the generating plant would become
unstable (failing to meet the System performance requirements of TPL-001-4 for a P1 event).
Requirement R4, Part 4.1.5 does not mandate that all RAS have redundant components. For
example:
•
Consider the instance where a RAS is installed to mitigate an extreme event in TPL-0014. There are no System performance requirements for extreme events; therefore, the
RAS does not need redundancy to meet the same performance requirements as those
required for the events and conditions for which the RAS was designed.
•
Consider a RAS that arms more load or generation than necessary such that failure of
the RAS to drop a portion of load or generation due to that single component failure will
still result in satisfactory System performance, as long as tripping the total armed
amount of load or generation does not cause other adverse impacts to reliability.
The scope of the periodic evaluation does not include a new review of the physical
implementation of the RAS, as this was confirmed by the RC during the initial review and
verified by subsequent functional testing. However, it is possible that a RAS design which
previously satisfied requirements for inadvertent RAS operation and single component failure
by means other than component redundancy may fail to satisfy these requirements at a later
time, and must be evaluated with respect to the current System. For example, if the actions of a
particular RAS include tripping load, load growth could occur over time that impacts the
amount of load to be tripped. These changes could result in tripping too much load upon
inadvertent operation and result in violations of Facility Ratings. Alternatively, the RAS might be
designed to trip more load than necessary (i.e., “over trip”) in order to satisfy single component
failure requirements. System changes could result in too little load being tripped and
unacceptable BES performance if one of the loads failed to trip.
Requirement R5
The correct operation of a RAS is important to maintain the reliability and integrity of the BES.
Any incorrect operation of a RAS indicates the RAS effectiveness and/or coordination may have
been compromised. Therefore, all operations of a RAS and failures of a RAS to operate when
expected must be analyzed to verify that the RAS operation was consistent with its intended
functionality and design.
A RAS operational performance analysis is intended to: (1) verify RAS operation is consistent
with implemented design; or (2) identify RAS performance deficiencies that manifested in the
incorrect RAS operation or failure of RAS to operate when expected.
The 120 full calendar day time frame for the completion of RAS operational performance
analysis aligns with the time frame established in Requirement R1 from PRC-004-4 regarding
the investigation of a Protection System Misoperation; however, flexibility is provided by
allowing the parties to negotiate a different schedule for the analysis. To promote reliability,
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the RAS-entity(s) is required to provide the results of RAS operational performance analyses to
its reviewing RC(s) if the analyses revealed a deficiency.
The RAS-entity(ies) may need to collaborate with its associated Transmission Planner to
comprehensively analyze RAS operational performance. This is because a RAS operational
performance analysis involves verifying that the RAS operation was triggered correctly (Part
5.1.1), responded as designed (Part 5.1.2), and that the resulting BES response (Parts 5.1.3 and
5.1.4) was consistent with the intended functionality and design of the RAS. Ideally, when there
is more than one RAS-entity for a RAS, the RAS-entities would collaborate to conduct and
submit a single, coordinated operational performance analysis.
Requirement R6
RAS deficiencies potentially pose a reliability risk to the BES. RAS deficiencies may be identified
in the periodic RAS evaluation conducted by the PC in Requirement R4, in the operational
analysis conducted by the RAS-entity in Requirement R5, or in the functional test performed by
the RAS-entity(ies) in Requirement R8. To mitigate potential reliability risks, Requirement R6
mandates that each RAS-entity participate in developing a CAP that establishes the mitigation
actions and timetable necessary to address the deficiency.
The RAS-entity(ies) that owns the RAS components, is responsible for the RAS equipment, and
is in the best position to develop the timelines and perform the necessary work to correct RAS
deficiencies. If necessary, the RAS-entity(ies) may request assistance with development of the
CAP from other parties such as its Transmission Planner or Planning Coordinator; however, the
RAS-entity has the responsibility for compliance with this requirement.
A CAP may require functional changes be made to a RAS. In this case, Attachment 1 information
must be submitted to the reviewing RC(s), an RC review must be performed to obtain RC
approval before the RAS-entity can place RAS modifications in- service, per Requirements R1,
R2, and R3.
Depending on the complexity of the issues, development of a CAP may require study,
engineering or consulting work. A timeframe of six full calendar months is allotted to allow
enough time for RAS-entity collaboration on the CAP development, while ensuring that
deficiencies are addressed in a reasonable time. Ideally, when there is more than one RASentity for a RAS, the RAS-entities would collaborate to develop and submit a single, coordinated
CAP. A RAS deficiency may require the RC or Transmission Operator to impose operating
restrictions so the System can operate in a reliable way until the RAS deficiency is resolved. The
possibility of such operating restrictions will incent the RAS-entity to resolve the issue as quickly
as possible.
The following are example situations of when a CAP is required:
•
A determination after a RAS operation/non-operation investigation that the RAS did not
meet performance expectations or did not operate as designed.
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•
Periodic planning assessment reveals RAS changes are necessary to correct performance or
coordination issues.
•
Equipment failures.
•
Functional testing identifies that a RAS is not operating as designed.
Requirement R7
Requirement R7 mandates that each RAS-entity implement its CAP developed in Requirement
R6 which mitigates the deficiencies identified in Requirements R4, R5, or R8. By definition, a
CAP is: “A list of actions and an associated timetable for implementation to remedy a specific
problem.”
A CAP can be modified if necessary to account for adjustments to the actions or scheduled
timetable of activities. If the CAP is changed, the RAS-entity must notify the reviewing Reliability
Coordinator(s). The RAS-entity must also notify the Reliability Coordinator(s) when the CAP has
been completed.
The implementation of a properly developed CAP ensures that RAS deficiencies are mitigated in
a timely manner. A RAS deficiency may require the RC or Transmission Operator to impose
operating restrictions so the System can operate in a reliable way until the CAP is completed.
The possibility of such operating restrictions will incent the RAS-entity to complete the CAP as
quickly as possible.
Requirement R8
The reliability objective of Requirement R8 is to test the non-Protection System components of
a RAS (controllers such as programmable logic controllers (PLCs)) and to verify the overall
performance of the RAS through functional testing. Functional tests validate RAS operation by
ensuring System states are detected and processed, and that actions taken by the controls are
correct and occur within the expected time using the in-service settings and logic. Functional
testing is aimed at assuring overall RAS performance and not the component focused testing
contained in the PRC-005 maintenance standard.
Since the functional test operates the RAS under controlled conditions with known System
states and expected results, testing and analysis can be performed with minimum impact to the
BES and should align with expected results. The RAS-entity is in the best position to determine
the testing procedure and schedule due to their overall knowledge of the RAS design,
installation, and functionality. Periodic testing provides the RAS-entity assurance that latent
failures may be identified and also promotes identification of changes in the System that may
have introduced latent failures.
The six and twelve full calendar year functional testing intervals are greater than the annual or
bi-annual periodic testing performed in some NERC Regions. However, these intervals are a
balance between the resources required to perform the testing and the potential reliability
impacts to the BES created by undiscovered latent failures that could cause an incorrect
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operation of the RAS. Longer test intervals for limited impact RAS are acceptable because
incorrect operations or failures to operate present a low reliability risk to the Bulk Power
System.
Functional testing is not synonymous with end-to-end testing. End-to-end testing is an
acceptable method but may not be feasible for many RAS. When end-to-end testing is not
possible, a RAS-entity may use a segmented functional testing approach. The segments can be
tested individually negating the need for complex maintenance schedules. In addition, actual
RAS operation(s) can be used to fulfill the functional testing requirement. If a RAS does not
operate in its entirety during a System event or System conditions do not allow an end-to-end
scheme test, then the segmented approach should be used to fulfill this Requirement.
Functional testing includes the testing of all RAS inputs used for detection, arming, operating,
and data collection. Functional testing, by default operates the processing logic and
infrastructure of a RAS, but focuses on the RAS inputs as well as the actions initiated by RAS
outputs to address the System condition(s) for which the RAS is designed. All segments and
components of a RAS must be tested or have proven operations within the applicable
maximum test interval to demonstrate compliance with the Requirement.
As an example of segment testing, consider a RAS controller implemented using a PLC that
receives System data, such as loading or line status, from distributed devices. These distributed
devices could include meters, protective relays, or other PLCs. In this example RAS, a line
protective relay is used to provide an analog metering quantity to the RAS control PLC. A
functional test would verify that the System data is received from the protective relay by the
PLC, processed by the PLC, and that PLC outputs are appropriate. There is no need to verify the
protective relay’s ability to measure the power system quantities, as this is a requirement for
Protection Systems used as RAS in PRC-005, Table 1-1, Component Type – Protective Relay.
Rather the functional test is focused on the use of the protective relay data at the PLC, including
the communications data path from relay to PLC if this data is essential for proper RAS
operation. Additionally, if the control signal back to the protective relay is also critical to the
proper functioning of this example RAS, then that path is also verified up- to the protective
relay. This example describes a test for one segment of a RAS which verifies RAS action, verifies
PLC control logic, and verifies RAS communications.
IEEE C37.233, “IEEE Guide for Power System Protection Testing,” 2009 section 8 (particularly
8.3-8.5), provides an overview of functional testing. The following opens section 8.3:
Proper implementation requires a well-defined and coordinated test plan for performance
evaluation of the overall system during agreed maintenance intervals. The maintenance test
plan, also referred to as functional system testing, should include inputs, outputs,
communication, logic, and throughput timing tests. The functional tests are generally not
component-level testing, rather overall system testing. Some of the input tests may need to be
done ahead of overall system testing to the extent that the tests affect the overall performance.
The test coordinator or coordinators need to have full knowledge of the intent of the scheme,
isolation points, simulation scenarios, and restoration to normal procedures.
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The concept is to validate the overall performance of the scheme, including the logic where
applicable, to validate the overall throughput times against system modeling for different types
of Contingencies, and to verify scheme performance as well as the inputs and outputs.
If a RAS passes a functional test, it is not necessary to provide that specific information to the
RC because that is the expected result and requires no further action. If a segment of a RAS fails
a functional test, the status of that degraded RAS is required to be reported (in Real-time) to
the Transmission Operator via PRC-001, Requirement R6, then to the RC via TOP-001-3,
Requirement R8. See Phase 2 of Project 2007-06 for the mapping document from PRC-001 to
other standards regarding notification of RC by TOP if a deficiency is found during testing.
Consequently, it is not necessary to include a similar requirement in this standard.
The initial test interval begins on the effective date of the standard pursuant to the
implementation plan. Subsequently, the maximum allowable interval between functional tests
is six full calendar years for RAS that are not designated as limited impact RAS and twelve full
calendar years for RAS that are designated as limited impact RAS. The interval between tests
begins on the date of the most recent successful test for each individual segment or end-to-end
test. A successful test of one segment only resets the test interval clock for that segment. A
RAS-entity may choose to count a correct RAS operation as a qualifying functional test for those
RAS segments which operate. If a System event causes a correct, but partial RAS operation,
separate functional tests of the segments that did not operate are still required within the
maximum test interval that started on the date of the previous successful test of those (nonoperating) segments in order to be compliant with Requirement R8.
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Requirement R9
The RAS database required to be maintained by the RC in Requirement R9 ensures information
regarding existing RAS is available. Attachment 3 contains the minimum information that is
required to be included about each RAS listed in the database. Additional information can be
requested by the RC.
The database enables the RC to provide other entities high-level information on existing RAS
that could potentially impact the operational and/or planning activities of that entity. The
information provided is sufficient for an entity with a reliability need to evaluate whether the
RAS can impact its System. For example, a RAS performing generation rejection to mitigate an
overload on a transmission line may cause a power flow change within an adjacent entity area.
This entity should be able to evaluate the risk that a RAS poses to its System from the high-level
information provided in the RAS database.
The RAS database does not need to list detailed settings or modeling information, but the
description of the System performance issues, System conditions, and the intended corrective
actions must be included. If additional details about the RAS operation are required, the entity
may obtain the contact information of the RAS-entity from the RC.
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Process Flow Diagram
The diagram below depicts the process flow of the PRC-012-2 requirements.
New RAS proposed
or RAS modified/
retired
Attachment 1
Attachment 2
R1
RAS-entity submits
RAS to RC for review
R2
RC Review Process
For new, modified,
or removal of RAS
RC Approves RAS as is
R3
RAS-entity accepts
approval
R9
RC updates RAS
database
Modify RAS per RC
direction
RC identified issues
With RAS
R3
RAS-entity
addresses issues
RAS
Database
Proposed alternative
to RC direction
Dated Report /
Analysis
Dated
communications
with RAS-entity(ies)
& RC
Yes
reset 5-year clock
Does CAP identify
RAS modification?
No
R4
PC – 5-year review
of RAS in the
planning area
RAS 5-year review
RAS operation or
non operation as
intended
Any deficiencies
identified?
R5
RAS entity determines if RAS
operated as intended (120 days
or an accepted alternative
schedule)
R6
RAS-entity proposes
Corrective Action
Plan within 6
months
Yes
No
R7
RAS-entity
implement the CAP
and update the CAP
until complete
Dated
documentation of
non operation or
operation not as
intended to RC
No
Work Management
documents
Maintenance
Records
Yes
Dated
documentation to
state correct
operation
Yes
At least once every 6
years (12 years –
limited impact)
R8
Perform functional
test of RAS
Any deficiencies
identified?
No
Dated
documentation of
functional testing
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Technical Justifications for Attachment 1 Content
Supporting Documentation for RAS Review
To perform an adequate review of the expected reliability implications of a Remedial Action
Scheme (RAS), it is necessary for the RAS-entity(ies) to provide a detailed list of information
describing the RAS to the reviewing RC. If there are multiple RAS-entities for a single RAS,
information will be needed from all RAS-entities. Ideally, in such cases, a single RAS-entity will
take the lead to compile all the data identified into a single Attachment 1.
The necessary data ranges from a general overview of the RAS to summarized results of
transmission planning studies, to information about hardware used to implement the RAS.
Coordination between the RAS and other RAS and protection and control systems will be
examined for possible adverse interactions. This review can include wide-ranging electrical
design issues involving the specific hardware, logic, telecommunications, and other relevant
equipment and controls that make up the RAS.
Attachment 1
The following checklist identifies important RAS information for each new or functionally
modified 8 RAS that the RAS-entity shall document and provide to the RC for review pursuant to
Requirement R1. When a RAS has been previously reviewed, only the proposed modifications
to that RAS require review; however, it will be helpful to each reviewing RC if the RAS-entity
provides a summary of the existing RAS functionality.
I. General
1. Information such as maps, one-line drawings, substation and schematic drawings that
identify the physical and electrical location of the RAS and related facilities.
Provide a description of the RAS to give an overall understanding of the functionality
and a map showing the location of the RAS. Identify other protection and control
systems requiring coordination with the RAS. See RAS Design below for additional
information.
Provide a single-line drawing(s) showing all sites involved. The drawing(s) should provide
sufficient information to allow the RC review team to assess design reliability, and
should include information such as the bus arrangement, circuit breakers, the
associated switches, etc. For each site, indicate whether detection, logic, action, or a
combination of these is present.
2. Functionality of new RAS or proposed functional modifications to existing RAS and
documentation of the pre- and post-modified functionality of the RAS.
8
Functionally Mmodified: Any modification to a RAS consisting of any of the following:
•
Changes to System conditions or contingencies monitored by the RAS
•
Changes to the actions the RAS is designed to initiate
•
Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of existing components
•
Changes to RAS logic beyond correcting existing errors
•
Changes to redundancy levels; i.e., addition or removal
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3. The Corrective Action Plan (CAP) if RAS modifications are proposed in a CAP.
[Reference NERC Reliability Standard PRC-012-2, Requirements R5 and R7]
Provide a description of any functional modifications to a RAS that are part of a CAP that
are proposed to address performance deficiency(ies) identified in the periodic
evaluation pursuant to Requirement R4, the analysis of an actual RAS operation
pursuant to Requirement R5, or functional test failure pursuant to Requirement R8. A
copy of the most recent CAP must be submitted in addition to the other data specified
in Attachment 1.
4. Initial data to populate the RAS database.
a. RAS name.
b. Each RAS-entity and contact information.
c. Expected or actual in-service date; most recent (Requirement R3) RC-approval date;
most recent five full calendar year (Requirement R4) evaluation date; and, date of
retirement, if applicable.
d. System performance issue or reason for installing the RAS (e.g., thermal overload,
angular instability, poor oscillation damping, voltage instability, under-/over-voltage,
slow voltage recovery).
e. Description of the Contingencies or System conditions for which the RAS was
designed (initiating conditions).
f. Corrective action taken by the RAS.
g. Identification of limited impact 9 RAS.
h. Any additional explanation relevant to high level understanding of the RAS.
Note: This is the same information as is identified in Attachment 3. Supplying the
data at this point in the review process ensures a more complete review and
minimizes any administrative burden on the reviewing RC(s).
II. Functional Description and Transmission Planning Information
1. Contingencies and System conditions that the RAS is intended to remedy.
[Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.1]
a. The System conditions that would result if no RAS action occurred should be
identified.
b. Include a description of the System conditions that should arm the RAS so as to be
ready to take action upon subsequent occurrence of the critical System
Contingencies or other operating conditions when RAS action is intended to occur.
If no arming conditions are required, this should also be stated.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
9
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c. Event-based RAS are triggered by specific Contingencies that initiate mitigating
action. Condition-based RAS may also be initiated by specific Contingencies, but
specific Contingencies are not always required. These triggering Contingencies
and/or conditions should be identified.
2. The actions to be taken by the RAS in response to disturbance conditions.
[Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.2]
Mitigating actions are designed to result in acceptable System performance. These
actions should be identified, including any time constraints and/or “backup” mitigating
measures that may be required in case of a single RAS component failure.
3. A summary of technical studies, if applicable, demonstrating that the proposed RAS
actions satisfy System performance objectives for the scope of System events and
conditions that the RAS is intended to remedy. The technical studies summary shall also
include information such as the study year(s), System conditions, and Contingencies
analyzed on which the RAS design is based, and the date those technical studies were
performed. [Reference NEC Reliability Standard PRC-014, R3.2]
Review the scheme purpose and impact to ensure it is (still) necessary, serves the
intended purposes, and meets current performance requirements. While copies of the
full, detailed studies may not be necessary, any abbreviated descriptions of the studies
must be detailed enough to allow the reviewing RC(s) to be convinced of the need for
the scheme and the results of RAS-related operations.
4. Information regarding any future System plans that will impact the RAS.
[Reference NERC Reliability Standard PRC-014, R3.2]
The RC’s other responsibilities under the NERC Reliability Standards focus on the
Operating Horizon, rather than the Planning Horizon. As such, the RC is less likely to be
aware of any longer range plans that may have an impact on the proposed RAS. Such
knowledge of future Plans is helpful to provide perspective on the capabilities of the
RAS.
5. RAS-entity proposal and justification for limited impact designation, if applicable.
A RAS designated as limited impact cannot, by inadvertent operation or failure to
operate, cause or contribute to BES Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of PRC-012-2 that has been through the
regional review processes of WECC or NPCC and is classified as either a Local Area
Protection Scheme (LAPS) in WECC or a Type 3 in NPCC is recognized as a limited impact
RAS upon the effective date of PRC-012-2 for the purposes of this standard and is
subject to all applicable requirements.
6. Documentation describing the System performance resulting from the possible
inadvertent operation of the RAS, except for limited impact RAS, caused by any single
RAS component malfunction. Single component malfunctions in a RAS not determined
to be limited impact must satisfy all of the following:
[Reference NERC Reliability Standard PRC-012, R1.4]
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a. The BES shall remain stable.
b. Cascading shall not occur.
c. Applicable Facility Ratings shall not be exceeded.
d. BES voltages shall be within post-Contingency voltage limits and post-Contingency
voltage deviation limits as established by the Transmission Planner and the Planning
Coordinator.
e. Transient voltage responses shall be within acceptable limits as established by the
Transmission Planner and the Planning Coordinator.
7. An evaluation indicating that the RAS settings and operation avoids adverse interactions
with other RAS, and protection and control systems.
[Reference NERC Reliability Standards PRC-012, R1.5 and PRC-014, R3.4]
RAS are complex schemes that may take action such as tripping load or generation or reconfiguring the System. Many RAS depend on sensing specific System configurations to
determine whether they need to arm or take actions. An examples of an adverse
interaction: A RAS that reconfigures the System also changes the available fault Fault
duty, which can affect distance relay overcurrent (“fault detector”) supervision and
ground overcurrent protection coordination.
8. Identification of other affected RCs.
This information is needed to aid in information exchange among all affected entities
and coordination of the RAS with other RAS and protection and control systems.
III.
Implementation
1. Documentation describing the applicable equipment used for detection, dc supply,
communications, transfer trip, logic processing, control actions, and monitoring.
Detection
Detection and initiating devices, whether for arming or triggering action, should be
designed to be secure. Several types of devices have been commonly used as disturbance,
condition, or status detectors:
•
Line open status (event detectors),
•
Protective relay inputs and outputs (event and parameter detectors),
•
Transducer and IED (analog) inputs (parameter and response detectors),
•
Rate of change (parameter and response detectors).
DC Supply
Batteries and charges, or other forms of dc supply for RAS, are commonly also used for
Protection Systems. This is acceptable, and maintenance of such supplies is covered by
PRC-005. However, redundant RAS systems, when used, should be supplied from
separately protected (fused or breakered) circuits.
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Communications: Telecommunications Channels
Telecommunications channels used for sending and receiving RAS information between
sites and/or transfer trip devices should meet at least the same criteria as other relaying
protection communication channels. Discuss performance of any non-deterministic
communication systems used (such as Ethernet).
The scheme logic should be designed so that loss of the channel, noise, or other channel
or equipment failure will not result in a false operation of the scheme.
It is highly desirable that the channel equipment and communications media (power line
carrier, microwave, optical fiber, etc.) be owned and maintained by the RAS-entity, or
perhaps leased from another entity familiar with the necessary reliability requirements.
All channel equipment should be monitored and alarmed to the dispatch center so that
timely diagnostic and repair action shall take place upon failure. Publicly switched
telephone networks are generally an undesirable option.
Communication channels should be well labeled or identified so that the personnel
working on the channel can readily identify the proper circuit. Channels between entities
should be identified with a common name at all terminals.
Transfer Trip
Transfer trip equipment, when separate from other RAS equipment, should be monitored
and labeled similarly to the channel equipment.
Logic Processing
All RAS require some form of logic processing to determine the action to take when the
scheme is triggered. Required actions are always scheme dependent. Different actions
may be required at different arming levels or for different Contingencies. Scheme logic
may be achievable by something as simple as wiring a few auxiliary relay contacts or by
much more complex logic processing.
Platforms that have been used reliably and successfully include PLCs in various forms,
personal computers (PCs), microprocessor protective relays, remote terminal units
(RTUs), and logic processors. Single-function relays have been used historically to
implement RAS, but this approach is now less common except for very simple new RAS or
minor additions to existing RAS.
Control Actions
RAS action devices may include a variety of equipment such as transfer trip, protective
relays, and other control devices. These devices receive commands from the logic
processing function (perhaps through telecommunication facilities) and initiate RAS
actions at the sites where action is required.
Monitoring by SCADA/EMS should include at least
•
Whether the scheme is in- service or out of service.
For RAS that are armed manually, the arming status may be the same as whether
the RAS is in- service or out of service.
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For RAS that are armed automatically, these two states are independent because
a RAS that has been placed in- service may be armed or unarmed based on
whether the automatic arming criteria have been met.
•
The current operational state of the scheme (available or not).
•
In cases where the RAS requires single component failure performance; e.g.,
redundancy, the minimal status indications should be provided separately for each
RASsystem.
The minimum status is generally sufficient for operational purposes; however,
where possible it is often useful to provide additional information regarding
partial failures or the status of critical components to allow the RAS-entity to
more efficiently troubleshoot a reported failure. Whether this capability exists
will depend in part on the design and vintage of equipment used in the RAS.
While all schemes should provide the minimum level of monitoring, new
schemes should be designed with the objective of providing monitoring at least
similar to what is provided for microprocessor-based Protection Systems.
2. Information on detection logic and settings/parameters that control the operation of
the RAS. [Reference NERC Reliability Standards PRC-012, R1.2 and PRC-013, R1.3]
Several methods to determine line or other equipment status are in common use, often
in combination:
a. Auxiliary switch contacts from circuit breakers and disconnect switches (52a/b,
89a/b)—the most common status monitor; “a” contacts exactly emulate actual
breaker status, while “b” contacts are opposite to the status of the breaker;
b. Undercurrent detection—a low level indicates an open condition, including at the far
end of a line; pickup is typically slightly above the total line-charging current;
c. Breaker trip coil current monitoring—typically used when high-speed RAS response
is required, but usually in combination with auxiliary switch contacts and/or other
detection because the trip coil current ceases when the breaker opens; and
d. Other detectors such as angle, voltage, power, frequency, rate of change of the
aforementioned, out of step, etc. are dependent on specific scheme requirements,
but some forms may substitute for or enhance other monitoring described in items
‘a’, ‘b’, and ‘c’ above.
Both RAS arming and action triggers often require monitoring of analog quantities such
as power, current, and voltage at one or more locations and are set to detect a specific
level of the pertinent quantity. These monitors may be relays, meters, transducers, or
other devices
3. Documentation showing that any multifunction device used to perform RAS function(s),
in addition to other functions such as protective relaying or SCADA, does not
compromise the reliability of the RAS when the device is not in- service or is being
maintained.
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In this context, a multifunction device (e.g., microprocessor-based relay) is a single
component that is used to perform the function of a RAS in addition to protective
relaying and/or SCADA simultaneously. It is important that other applications in the
multifunction device do not compromise the functionality of the RAS when the device is
in service or when it is being maintained. The following list outlines considerations when
the RAS function is applied in the same microprocessor-based relay as equipment
protection functions:
a. Describe how the multifunction device is applied in the RAS.
b. Show the general arrangement and describe how the multi-function device is
labeled in the design and application, so as to identify the RAS and other device
functions.
c. Describe the procedures used to isolate the RAS function from other functions in the
device.
d. Describe the procedures used when each multifunction device is removed from
service and whether coordination with other protection schemes is required.
e. Describe how each multifunction device is tested, both for commissioning and
during periodic maintenance testing, with regard to each function of the device.
f. Describe how overall periodic RAS functional and throughput tests are performed if
multifunction devices are used for both local protection and RAS.
g. Describe how upgrades to the multifunction device, such as firmware upgrades, are
accomplished. How is the RAS function taken into consideration?
Other devices that are usually not considered multifunction devices such as auxiliary
relays, control switches, and instrument transformers may serve multiple purposes such
as protection and RAS. Similar concerns apply for these applications as noted above.
4. Documentation describing the System performance resulting from a single component
failure in the RAS, except for limited impact RAS, when the RAS is intended to operate. A
single component failure in a RAS not determined to be limited impact must not prevent
the BES from meeting the same performance requirements (defined in Reliability
Standard TPL-001-4 or its successor) as those required for the events and conditions for
which the RAS is designed. The documentation should describe or illustrate how the
design achieves this objective. [Reference NERC Reliability Standard PRC-012, R1.3]
RAS automatic arming, if applicable, is vital to RAS and System performance and is
therefore included in this requirement.
Acceptable methods to achieve this objective include, but are not limited to the
following:
a. Providing redundancy of RAS components. Typical examples are listed below:
i.
Draft 3 of PRC-012-2
FebruaryApril 2016
Protective or auxiliary relays used by the RAS.
Page 50 of 53
Supplemental Material
ii.
Communications systems necessary for correct operation of the RAS.
iii.
Sensing devices used to measure electrical or other quantities used by the RAS.
iv.
Station dc supply associated with RAS functions.
v.
Control circuitry associated with RAS functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
vi.
Logic processing devices that accept System inputs from RAS components or
other sources, make decisions based on those inputs, or initiate output signals
to take remedial actions.
b. Arming more load or generation than necessary such that failure of the RAS to drop
a portion of load or generation due to that single component failure will still result in
satisfactory System performance, as long as tripping the total armed amount of load
or generation does not cause other adverse impacts to reliability.
c. Using alternative automatic actions to back up failures of single RAS components.
d. Manual backup operations, using planned System adjustments such as Transmission
configuration changes and re-dispatch of generation, if such adjustments are
executable within the time duration applicable to the Facility Ratings.
5. Documentation describing the functional testing process.
IV.
RAS Retirement
The following checklist identifies important RAS information for each existing RAS to be
retired that the RAS-entity shall document and provide to the Reliability Coordinator for
review pursuant to Requirement R1.
1. Information necessary to ensure that the Reliability Coordinator is able to understand
the physical and electrical location of the RAS and related facilities.
2. A summary of technical studies and technical justifications, if applicable, upon which the
decision to retire the RAS is based.
3. Anticipated date of RAS retirement.
While the documentation necessary to evaluate RAS removals is not as extensive as for
new or functionally modified RAS, it is still vital that, when the RAS is no longer
available, System performance will still meet the appropriate (usually TPL) requirements
for the Contingencies or System conditions that the RAS had been installed to
remediate.
Draft 3 of PRC-012-2
FebruaryApril 2016
Page 51 of 53
Supplemental Material
Technical Justification for Attachment 2 Content
Reliability Coordinator RAS Review Checklist
Attachment 2 is a checklist provided to facilitate consistent reviews continent-wide for new or
functionally modified RAS prior to the RAS installation. The checklist is meant to assist the RC in
identifying reliability-related considerations relevant to various aspects of RAS design and
implementation.
Technical Justifications for Attachment 3 Content
Database Information
Attachment 3 contains the minimum information that the RC must consolidate into its database
for each RAS in its area.
1. RAS name.
•
The name used to identify the RAS.
2. Each RAS-entity and contact information.
•
A reliable phone number or email address should be included to contact each RAS-entity
if more information is needed.
3. Expected or actual in-service date; most recent (Requirement R3) RC-approval date; most
recent five full calendar year (Requirement R4) evaluation date; and, date of retirement, if
applicable.
•
Specify each applicable date.
4. System performance issue or reason for installing the RAS (e.g., thermal overload, angular
instability, poor oscillation damping, voltage instability, under-/over-voltage, slow voltage
recovery).
•
A short description of the reason for installing the RAS is sufficient, as long as the main
System issues addressed by the RAS can be identified by someone with a reliability
need.
5. Description of the Contingencies or System conditions for which the RAS was designed
(initiating conditions).
•
A high level summary of the conditions/Contingencies is expected. Not all combinations
of conditions are required to be listed.
6. Corrective action taken by the RAS.
•
A short description of the actions should be given. For schemes shedding load or
generation, the maximum amount of megawatts should be included.
Draft 3 of PRC-012-2
FebruaryApril 2016
Page 52 of 53
Supplemental Material
7. Identification of limited impact 10 RAS.
•
Specify whether or not the RAS is designated as limited impact.
8. Any additional explanation relevant to high-level understanding of the RAS.
•
If deemed necessary, any additional information can be included in this section, but is
not mandatory.
A RAS designated as limited impact cannot, by inadvertent operation or failure to operate, cause or contribute to BES
Cascading, uncontrolled separation, angular instability, voltage instability, voltage collapse, or unacceptably damped
oscillations.
10
Draft 3 of PRC-012-2
FebruaryApril 2016
Page 53 of 53
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
• PRC-012-2 – Remedial Action Schemes
Requested Withdrawals
• PRC-012-1 – Remedial Action Scheme Review Procedure
•
PRC-013-1 – Remedial Action Scheme Database
•
PRC-014-1 – Remedial Action Scheme Assessment
Requested Retirements
• PRC-015-1 – Remedial Action Scheme Data and Documentation
•
PRC-016-1 – Remedial Action Scheme Misoperations
Applicable Entities
• Reliability Coordinator
•
Planning Coordinator
•
RAS-entity – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part
of a RAS
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for Remedial
Action Scheme (“RAS”) and associated revisions to related Reliability Standards to consolidate that term
with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC-012-0, PRC-013-0, and PRC-014-0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not enforceable,
NERC revised these standards to account for the RAS definition revision and changed relevant version
numbers to reflect the change. Because of this change, NERC requested retirement of PRC-012-0, PRC013-0, and PRC-014-0, and provided, for informational purposes only, updated Reliability Standards PRC012-1, PRC-013-1, and PRC-014-1. In the same Petition, NERC requested retirement of PRC-015-0 and PRC016-0.1 and approval of Reliability Standards PRC-015-1 and PRC-016-1, again implementing changes
stemming from the revised definition of RAS.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards.
General Considerations
Reliability Standard PRC-012-2 was developed to consolidate previously unapproved standards which
were designated by the Commission as “fill-in-the-blank” standards and to revise other RAS-related
standards. Reliability Standard PRC-012-2 also provides clear and unambiguous responsibilities to the
specific users, owners, and operators of the Bulk-Power System. Reliability Standard PRC-012-2 establishes
a new working framework between RAS-entities, PCs, and RCs, and this new framework will involve
considerable start-up effort. As such, implementation of Reliability Standard PRC-012-2 will occur over a
thirty six (36) month period after approval of the standard by applicable governmental authorities.
Limited Impact RAS
A RAS implemented prior to the effective date of PRC-012-2 that has been through the regional review
processes of WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC or a
Type III in NPCC is recognized as a limited impact RAS upon the effective date of PRC-012-2 and is subject
to all applicable requirements.
Effective Date
Where approval by an applicable governmental authority is required, Reliability Standard PRC-012-2 shall
become effective on the first day of the first calendar quarter that is thirty six (36) months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Provisions concerning the initial performance of
obligations under Requirements R4, R8, and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is thirty six (36) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Provisions concerning the initial performance of obligations under Requirements R4, R8, and R9 are
outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within five
(5) full calendar years after the effective date of PRC‐012‐2, as described above.
For new or functionally modified RAS, the initial performance of Requirement R4 must be completed within
five (5) full calendar years after the date that the RAS is approved by the reviewing RC(s) under Requirement
R3.
Implementation Plan for PRC-012-2 | April 2016
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Page 2 of 3
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years after the effective date for PRC-012-2, as
described above.
For each RAS designated as limited impact, initial performance of obligations under Requirement R8 must
be completed at least once within twelve (12) full calendar years after the effective date for PRC-012-2, as
described above.
Requirement R9
For each Reliability Coordinator that does not have a RAS database, the initial obligation under
Requirement R9 is to establish a database by the effective date of PRC-012-2.
Each Reliability Coordinator will perform the obligation of Requirement R9 within twelve full calendar
months after the effective date of PRC-012-2, as described above.
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the effective date of PRC-0122 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC-012-2 | April 2016
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Page 3 of 3
Implementation Plan for PRC-012-2
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
Requested Approval
PRC‐012‐2 – Remedial Action Schemes
Requested Withdrawals
Requested Retirements
PRC‐012‐1 – Remedial Action Scheme Review Procedure
PRC‐013‐1 – Remedial Action Scheme Database
PRC‐014‐1 – Remedial Action Scheme Assessment
Requested Retirements
PRC‐015‐1 – Remedial Action Scheme Data and Documentation
PRC‐016‐1 – Remedial Action Scheme Misoperations
Applicable Entities
Reliability Coordinator
Planning Coordinator
RAS‐entity – the Transmission Owner, Generator Owner, or Distribution Provider that owns all or part
of a RAS
Background
On November 13, 2014, the NERC Board of Trustees approved revisions to the definition for Remedial
Action Scheme (“RAS”) and associated revisions to related Reliability Standards to consolidate that term
with the Glossary term “Special Protection System” (SPS).
In its February 3, 2015 petition to the Commission for approval of the definition of RAS and associated
Reliability Standards (“Petition”), NERC noted that, although PRC‐012‐0, PRC‐013‐0, and PRC‐014‐0 were
neither approved nor remanded by the Commission in Order No. 693 and were therefore not enforceable,
NERC revised these standards to account for the RAS definition revision and changed relevant version
numbers to reflect the change. Because of this change, NERC requested retirement of PRC‐012‐0, PRC‐
013‐0, and PRC‐014‐0, and provided, for informational purposes only, updated Reliability Standards PRC‐
012‐1, PRC‐013‐1, and PRC‐014‐1. In the same Petition, NERC requested retirement of PRC‐015‐0 and PRC‐
016‐0.1 and approval of Reliability Standards PRC‐015‐1 and PRC‐016‐1, again implementing changes
stemming from the revised definition of RAS.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards.
General Considerations
Reliability Standard PRC‐012‐2 was developed to consolidate previously unapproved standards which
were designated by the Commission as “fill‐in‐the‐blank” standards and to revise other RAS‐related
standards. Reliability Standard PRC‐012‐2 also provides clear and unambiguous responsibilities to the
specific users, owners, and operators of the Bulk‐Power System. Reliability Standard PRC‐012‐2 establishes
a new working framework between RAS‐entities, PCs, and RCs, and this new framework will involve
considerable start‐up effort. As such, implementation of Reliability Standard PRC‐012‐2 will occur over a
thirty six (36) month period after approval of the standard by applicable governmental authorities.
Limited Impact RAS
A RAS implemented prior to the effective date of PRC‐012‐2 that has been through the regional review
processes of WECC or NPCC and is classified as either a Local Area Protection Scheme (LAPS) in WECC or a
Type 3 III in NPCC is recognized as a limited impact RAS upon the effective date of PRC‐012‐2 and is subject
to all applicable requirements.
Effective Date
Where approval by an applicable governmental authority is required, Reliability Standard PRC‐012‐2 shall
become effective on the first day of the first calendar quarter that is thirty six (36) months after the
effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Provisions concerning the initial performance of
obligations under Requirements R4, R8, and R9 are outlined below.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is thirty six (36) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Provisions concerning the initial performance of obligations under Requirements R4, R8, and R9 are
outlined below.
Requirement R4
For existing RAS, initial performance of obligations under Requirement R4 must be completed within five
(5) full calendar years after the effective date of PRC‐012‐2, as described above.
Implementation Plan for PRC‐012‐2 | April 2016
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
FebruaryApril
2016
Page 2 of 5
For new or functionally modified RAS, the initial performance of Requirement R4 must be completed within
five (5) full calendar years after the date that the RAS is approved by the reviewing RC(s) under Requirement
R3.
Implementation Plan for PRC‐012‐2 | April 2016
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
FebruaryApril
2016
Page 3 of 5
Requirement R8
For each RAS not designated as limited impact, initial performance of obligations under Requirement R8
must be completed at least once within six (6) full calendar years after the effective date for PRC‐012‐2, as
described above.
For each RAS designated as limited impact, initial performance of obligations under Requirement R8 must
be completed at least once within twelve (12) full calendar years after the effective date for PRC‐012‐2, as
described above.
Implementation Plan for PRC‐012‐2 | April 2016
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
FebruaryApril
2016
Page 4 of 5
Requirement R9
For each Reliability Coordinator that does not have a RAS database, the initial obligation under
Requirement R9 is to establish a database by the effective date of PRC‐012‐2.
Each Reliability Coordinator will perform the obligation of Requirement R9 within twelve full calendar
months after the effective date of PRC‐012‐2, as described above.
Retirement of Existing Standards
The Reliability Standards for retirement shall be retired immediately prior to the effective date of PRC‐012‐
2 in the particular jurisdiction in which the standard is becoming effective.
Implementation Plan for PRC‐012‐2 | April 2016
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
FebruaryApril
2016
Page 5 of 5
Revised Definition of “Special Protection System”
Special Protection System (SPS)
Background
In Order No. 693, the Commission approved, among other things, the Glossary of Terms Used in NERC
Reliability Standards (“NERC Glossary”), which included NERC’s currently effective definitions of Special
Protection System and Remedial Action Scheme. The NERC Glossary currently defines a Special Protection
System as:
An automatic protection system designed to detect abnormal or predetermined system
conditions, and take corrective actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may include changes in demand,
generation (MW and Mvar), or system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load
shedding or (b) fault conditions that must be isolated or (c) out-of-step relaying (not designed as
an integral part of an SPS). Also called Remedial Action Scheme.
The currently effective NERC Glossary definition for “Remedial Action Scheme” is a cross-reference to the
definition of Special Protection System and reads: “See ‘Special Protection System.’” This internal crossreference from Remedial Action Scheme to Special Protection System in lieu of a separate definition was
developed to ensure that the terms are used interchangeably even where entities or an interconnection
uses one term versus the other.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” to add clarity and to ensure proper identification of Remedial Action Schemes and a more
consistent application of related Reliability Standards. As explained in the petition, “[t]he defined terms
‘Special Protection System’ and ‘Remedial Action Scheme’ are currently used interchangeably throughout
the NERC Regions and in various Reliability Standards, including prior versions of the Proposed Reliability
Standards.” Along with this proposed revised definition, NERC submitted revisions to various Reliability
Standards by replacing the term “Special Protection System” and replacing it with the newly revised
“Remedial Action Scheme.” As NERC stated, “use of only one term in the NERC Reliability Standards will
ensure proper identification of these systems and application of related Reliability Standards.” The
petition also anticipated future revision to the definition of “Special Protection System” to cross-reference
the newly revised and proposed definition of “Remedial Action Scheme.” This coordination, which would
be achieved by implementing the new definition of “Special Protection System” simultaneously with the
Commission approval of the revised definition for “Remedial Action Scheme,” will ensure that all
references to “Special Protection System” and “Remedial Action Scheme” refer to the same revised
definition.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards.
Revised Definition
Special Protection System (SPS)
See “Remedial Action Scheme”
Revised Definition of “Special Protection System” (SPS) | April 2016
2
Proposed Revised Definition of “Special Protection System”
Special Protection System (SPS)
Background
In Order No. 693, the Commission approved, among other things, the Glossary of Terms Used in NERC
Reliability Standards (“NERC Glossary”), which included NERC’s currently effective definitions of Special
Protection System and Remedial Action Scheme. The NERC Glossary currently defines a Special Protection
System as:
An automatic protection system designed to detect abnormal or predetermined system
conditions, and take corrective actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may include changes in demand,
generation (MW and Mvar), or system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load
shedding or (b) fault conditions that must be isolated or (c) out-of-step relaying (not designed as
an integral part of an SPS). Also called Remedial Action Scheme.
The currently- effective NERC Glossary definition for “Remedial Action Scheme” is a cross-reference to the
definition of Special Protection System and reads: “See ‘Special Protection System.’” This internal crossreferences from Remedial Action Scheme to Special Protection System in lieu of a separate definition was
developed to ensure that the terms are used interchangeably even where entities or an interconnection
uses one term versus the other.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” to add clarity and to ensure proper identification of Remedial Action Schemes and a more
consistent application of related Reliability Standards. As explained in the petition, “[t]he defined terms
‘Special Protection System’ and ‘Remedial Action Scheme’ are currently used interchangeably throughout
the NERC Regions and in various Reliability Standards, including prior versions of the Proposed Reliability
Standards.” Along with this proposed revised definition, NERC submitted revisions to various Reliability
Standards by replacing the term “Special Protection System” and replacing it with the newly revised
“Remedial Action Scheme.” As NERC stated, “use of only one term in the NERC Reliability Standards will
ensure proper identification of these systems and application of related Reliability Standards.” The
petition also anticipated future revision to the definition of “Special Protection System” to cross-reference
the newly revised and proposed definition of “Remedial Action Scheme.” This coordination, which would
be achieved by implementing the new definition of “Special Protection System” simultaneously with the
Commission approval of the revised definition for “Remedial Action Scheme,” will ensure that all
references to “Special Protection System” and “Remedial Action Scheme” refer to the same revised
definition.
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to accept
the revisions to the RAS definition and associated standards, and on November 19, 2015, the Commission
issued a Final Order approving the RAS definition and associated standards.
Proposed Revised Definition
Special Protection System (SPS)
See “Remedial Action Scheme”
Proposed Revised Definition of “Special Protection System” (SPS) | November April 20152016
2
Implementation Plan for the Revised
Definition of “Special Protection System”
Project 2010-05.3 – Remedial Action Scheme (RAS)
Requested Approval
Definition of “Special Protection System”
Requested Retirement
Existing definition of “Special Protection System”
Background
In Order No. 693, the Commission approved, among other things, the Glossary of Terms Used in NERC
Reliability Standards (“NERC Glossary”), which included NERC’s currently effective definitions of Special
Protection System and Remedial Action Scheme. The NERC Glossary currently defines a Special
Protection System as:
An automatic protection system designed to detect abnormal or predetermined system
conditions, and take corrective actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may include changes in demand,
generation (MW and Mvar), or system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load
shedding or (b) fault conditions that must be isolated or (c) out‐of‐step relaying (not designed as
an integral part of an SPS). Also called Remedial Action Scheme.
The currently effective NERC Glossary definition for “Remedial Action Scheme” is a cross‐reference to
the definition of Special Protection System and reads: “See ‘Special Protection System.’” This internal
cross‐reference from Remedial Action Scheme to Special Protection System in lieu of a separate
definition was developed to ensure that the terms are used interchangeably even where entities or an
interconnection uses one term versus the other.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” developed by the standard drafting team Project 2010‐05.2 (SPS SDT). As explained in the
petition, “[t]he defined terms ‘Special Protection System’ and ‘Remedial Action Scheme’ are currently
used interchangeably throughout the NERC Regions and in various Reliability Standards, including prior
versions of the Proposed Reliability Standards.” In developing a solution for this inconsistency, the SPS
SDT revised the definition of Remedial Action Scheme to incorporate a higher level of specificity for
schemes that are appropriately considered Remedial Action Schemes, to provide more consistent
identification of Remedial Action Schemes across the NERC Regions, and to state the relationship
between Protection Systems and Remedial Action Schemes. NERC also submitted revisions to various
Implementation Plan for the Revised Definition of “Special Protection System”
Project 2010‐05.3 – Remedial Action Schemes | April 2016
1
Reliability Standards by replacing the term “Special Protection System” with the newly revised “Remedial
Action Scheme.” As NERC stated, the “use of only one term in the NERC Reliability Standards will ensure
proper identification of these systems and application of related Reliability Standards.”
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to
accept the revisions to the RAS definition and associated standards, and on November 19, 2015, the
Commission issued a Final Order approving the RAS definition and associated standards.
General Considerations
The petition for revisions to the Definition of “Remedial Action Scheme” and related Reliability
Standards also anticipated revision of the definition of “Special Protection System” to cross‐reference
the newly revised definition of “Remedial Action Scheme.” Coordination of the two terms was
completed by the SPS SDT in this phase of the Project (Project 2010‐05.3) and will implement the new
definition of “Special Protection System” simultaneously with the effective date of the revised definition
for “Remedial Action Scheme.” By assigning simultaneous effective dates of the revised definition of
“Special Protection System” and “Remedial Action Scheme,” all references to either term in NERC or
Regional Entity documents will refer to the same NERC Glossary definition.
Effective Dates
Where approval by an applicable governmental authority is required, the revised definition of Special
Protection System shall become effective on the later of the effective date of the applicable
governmental authority’s order approving the revised definition of Special Protection System or the
effective date of the revised definition of Remedial Action Scheme approved by the Commission on
November 19, 2015.
Where approval by an applicable governmental authority is not required, the revised definition of
Special Protection System shall become effective on the later of the day that it is adopted by the NERC
Board of Trustees, or as otherwise provided for in that jurisdiction, or the effective date of the revised
definition of Remedial Action Scheme as approved by the Commission on November 19, 2015.
Retirement
The currently effective definition of Special Protection System shall be retired immediately prior to the
effective date of the revised definition of Special Protection System in the particular jurisdiction in
which the definition is becoming effective.
Implementation Plan for the Revised Definition of “Special Protection System”
Project 2010‐05.3 – Remedial Action Schemes | April 2016
2
Implementation Plan for the Revised
Definition of “Special Protection System”
Project 2010-05.3 – Remedial Action Scheme (RAS)
Requested Approval
Definition of “Special Protection System”
Requested Retirement
Existing definition of “Special Protection System”
Background
In Order No. 693, the Commission approved, among other things, the Glossary of Terms Used in NERC
Reliability Standards (“NERC Glossary”), which included NERC’s currently effective definitions of Special
Protection System and Remedial Action Scheme. The NERC Glossary currently defines a Special
Protection System as:
An automatic protection system designed to detect abnormal or predetermined system
conditions, and take corrective actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may include changes in demand,
generation (MW and Mvar), or system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load
shedding or (b) fault conditions that must be isolated or (c) out‐of‐step relaying (not designed as
an integral part of an SPS). Also called Remedial Action Scheme.
The currently‐ effective NERC Glossary definition for “Remedial Action Scheme” is a cross‐reference to
the definition of Special Protection System and reads: “See ‘Special Protection System.’” This internal
cross‐references from Remedial Action Scheme to Special Protection System in lieu of a separate
definition was developed to ensure that the terms are used interchangeably even where entities or an
interconnection uses one term versus the other.
On February 3, 2015, NERC submitted a petition for approval of a revised definition of “Remedial Action
Scheme” developed by the standard drafting team Project 2010‐05.2 (SPS SDT). As explained in the
petition, “[t]he defined terms ‘Special Protection System’ and ‘Remedial Action Scheme’ are currently
used interchangeably throughout the NERC Regions and in various Reliability Standards, including prior
versions of the Proposed Reliability Standards.” In developing a solution for this inconsistency, the SPS
SDT revised the definition of Remedial Action Scheme to incorporate a higher level of specificity for
schemes that are appropriately considered Remedial Action Schemes, to provide more consistent
identification of Remedial Action Schemes across the NERC Regions, and to state the relationship
between Protection Systems and Remedial Action Schemes. NERC also submitted revisions to various
Implementation Plan for the Revised Definition of “Special Protection System”
Project 2010‐05.3 – Remedial Action Schemes | April 2016
1
Reliability Standards by replacing the term “Special Protection System” with the newly revised “Remedial
Action Scheme.” As NERC stated, the “use of only one term in the NERC Reliability Standards will ensure
proper identification of these systems and application of related Reliability Standards.”
On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to
accept the revisions to the RAS definition and associated standards, and on November 19, 2015, the
Commission issued a Final Order approving the RAS definition and associated standards.
General Considerations
The petition for revisions to the Definition of “Remedial Action Scheme” and related Reliability
Standards also anticipated revision of the definition of “Special Protection System” to cross‐reference
the newly revised definition of “Remedial Action Scheme.” Coordination of the two terms was
completed by the SPS SDT in this phase of the Project (Project 2010‐05.3) and will implement the new
definition of “Special Protection System” simultaneously with the effective date of the revised definition
for “Remedial Action Scheme.” By assigning simultaneous effective dates of the revised definition of
“Special Protection System” and “Remedial Action Scheme,” all references to either term in NERC or
Regional Entity documents will refer to the same NERC Glossary definition.
Effective Dates
Where approval by an applicable governmental authority is required, the revised definition of Special
Protection System shall become effective on the later of the effective date of the applicable
governmental authority’s order approving the revised definition of Special Protection System or the
effective date of the revised definition of Remedial Action Scheme approved by the Commission on
November 19, 2015.
Where approval by an applicable governmental authority is not required, the revised definition of
Special Protection System shall become effective on the later of the day that it is adopted by the NERC
Board of Trustees, or as otherwise provided for in that jurisdiction, or the effective date of the revised
definition of Remedial Action Scheme as approved by the Commission on November 19, 2015.
Retirement
The currently effective definition of Special Protection Systems shall be retired immediately prior to the
effective date of the revised definition of Special Protection Systems in the particular jurisdiction in
which the definition is becoming effective.
Implementation Plan for the Revised Definition of “Special Protection System”
Project 2010‐05.3 – Remedial Action Schemes | April 2016
2
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
R1.1. Description of the process for submitting a
proposed RAS for Regional Reliability
Organization review.
R1.2. Requirements to provide data that describes
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
shall be designed so that a single RAS
component failure, when the RAS was
intended to operate, does not prevent the
interconnected transmission system from
meeting the performance requirements
defined in Reliability Standards TPL-001-0,
TPL-002-0, and TPL-003-0.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC-012-1 R.1.1:
Covered by Requirements R1,
R2 and R3
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC-012-1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC-012-1 R.1.3:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.5
PRC-012-1 R.1.4:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2, and
Requirement R4, Part 4.1.4
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was
designed, and not exceed TPL-003-0.
PRC-012-1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
R1.5. Requirements to demonstrate the proposed
RAS will coordinate with other protection
and control systems and applicable Regional
Reliability Organization Emergency
procedures.
PRC-012-1 R.1.6:
Covered by Requirement R5
Existing Requirement in Reliability Standard
R1.6. Regional Reliability Organization definition
of misoperation.
R1.7. Requirements for analysis and
documentation of corrective action plans for
all RAS misoperations.
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-012-1 R.1.7:
Covered by Requirements R5
and R6
PRC-012-1 R.1.8:
PRC-012-2 NERC Standards
Development Process
PRC-012-1 R.1.9:
Covered by Requirement R8
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS-entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
4
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
performance and the proper operation of non-Protection
System components:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
•
At least once every six full calendar years for all
RAS not designated as limited impact, or
•
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-013-1 R1:
Covered by Requirement R9
PRC-013-1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-014-1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-014-1 R2:
Covered by Requirement R4
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
PRC-014-1 R3:
Covered by Requirement R4
R3.1. Identification of group conducting the assessment
and the date the assessment was performed.
PRC-014-1 R3.1 - R3.4:
Covered by Requirement R4
R3.2. Study years, system conditions, and contingencies
analyzed in the technical studies on which the
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-014-1 R3.5:
Covered by Requirement R6
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non-compliant
RAS.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for limited impact RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
11
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall maintain
a list of and provide data for existing and proposed
RAS as specified in Reliability Standard PRC-013-1
R1.
PRC-015-1 R1:
Covered by Requirement R1,
Attachment 1
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC-012-1_R1 prior to being placed in
service.
PRC-015-1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3
R1. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS in
service or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
Retired P81
N/A
13
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC-012-1_R1.
Translation to New
Standard or Other Action
PRC-016-1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
PRC-016-1 R2:
Covered by Requirements R6
and R7
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
PRC-016-1 R3:
Covered by Requirements R5,
R6, and R7, Attachment 1
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
17
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
Mapping Document | April 2016
Project 2010-05.3 Phase 3 of Protection Systems (RAS)
18
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
R1.1. Description of the process for submitting a
proposed RAS for Regional Reliability
Organization review.
R1.2. Requirements to provide data that describes
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
shall be designed so that a single RAS
component failure, when the RAS was
intended to operate, does not prevent the
interconnected transmission system from
meeting the performance requirements
defined in Reliability Standards TPL-001-0,
TPL-002-0, and TPL-003-0.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC-012-1 R.1.1:
Covered by Requirements R1,
R2 and R3
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC-012-1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC-012-1 R.1.3:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.5
PRC-012-1 R.1.4:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2, and
Requirement R4, Part 4.1.4
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was
designed, and not exceed TPL-003-0.
PRC-012-1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
R1.5. Requirements to demonstrate the proposed
RAS will coordinate with other protection
and control systems and applicable Regional
Reliability Organization Emergency
procedures.
PRC-012-1 R.1.6:
Covered by Requirement R5
Existing Requirement in Reliability Standard
R1.6. Regional Reliability Organization definition
of misoperation.
R1.7. Requirements for analysis and
documentation of corrective action plans for
all RAS misoperations.
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
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Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-012-1 R.1.7:
Covered by Requirements R5
and R6
PRC-012-1 R.1.8:
PRC-012-2 NERC Standards
Development Process
PRC-012-1 R.1.9:
Covered by Requirement R8
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS-entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
4
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
performance and the proper operation of non-Protection
System components:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
•
At least once every six full calendar years for all
RAS not designated as limited impact, or
•
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-013-1 R1:
Covered by Requirement R9
PRC-013-1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-014-1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-014-1 R2:
Covered by Requirement R4
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
R3.1. Identification of group conducting the assessment
and the date the assessment was performed.
R3.2. Study years, system conditions, and contingencies
analyzed in the technical studies on which the
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-014-1 R3:
Covered by Requirement R4
PRC-014-1 R3.1 - R3.4:
Covered by Requirement R4
PRC-014-1 R3.5:
Covered by Requirement R6
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non-compliant
RAS.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
11
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall maintain
a list of and provide data for existing and proposed
RAS as specified in Reliability Standard PRC-013-1
R1.
PRC-015-1 R1:
Covered by Requirement R1,
Attachment 1
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC-012-1_R1 prior to being placed in
service.
PRC-015-1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
Retired P81
N/A
13
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC-012-1_R1.
Translation to New
Standard or Other Action
PRC-016-1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-016-1 R2:
Covered by Requirements R6
and R7
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
PRC-016-1 R3:
Covered by Requirements R5,
R6, and R7, Attachment 1
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
17
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
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Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
18
Mapping Document
Project 2010-5.3 Phase 3 of Protection Systems: Remedial Action Schemes
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
R1. Each Regional Reliability Organization with a
Transmission Owner, Generator Owner, or
Distribution Providers that uses or is planning to use
a RAS shall have a documented Regional Reliability
Organization RAS review procedure to ensure that
RAS comply with Regional criteria and NERC
Reliability Standards. The Regional RAS review
procedure shall include:
R1.1. Description of the process for submitting a
proposed RAS for Regional Reliability
Organization review.
R1.2. Requirements to provide data that describes
design, operation, and modeling of a RAS.
R1.3. Requirements to demonstrate that the RAS
shall be designed so that a single RAS
component failure, when the RAS was
intended to operate, does not prevent the
interconnected transmission system from
meeting the performance requirements
defined in Reliability Standards TPL-001-0,
TPL-002-0, and TPL-003-0.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
PRC-012-1 R.1.1:
Covered by Requirements R1,
R2 and R3
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
PRC-012-1 R.1.2:
Covered by Requirement R1,
Attachment 1
PRC-012-1 R.1.3:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.5
PRC-012-1 R.1.4:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2, and
Requirement R4, Part 4.1.4
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying reliability issue(s) shall resolve
each issue to obtain approval of the RAS from each
reviewing Reliability Coordinator.
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
Reliability Standard: PRC-012-1
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.4. Requirements to demonstrate that the
inadvertent operation of a RAS shall meet
the same performance requirement (TPL001-0, TPL-002-0, and TPL-003-0) as that
required of the contingency for which it was
designed, and not exceed TPL-003-0.
PRC-012-1 R.1.5:
Covered by Requirement R1,
Attachments 1, Requirement
R2, Attachment 2 and
Requirement R4, Part 4.1.2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
R1.5. Requirements to demonstrate the proposed
RAS will coordinate with other protection
and control systems and applicable Regional
Reliability Organization Emergency
procedures.
PRC-012-1 R.1.6:
Covered by Requirement R5
Existing Requirement in Reliability Standard
R1.6. Regional Reliability Organization definition
of misoperation.
R1.7. Requirements for analysis and
documentation of corrective action plans for
all RAS misoperations.
R1.8. Identification of the Regional Reliability
Organization group responsible for the
Regional Reliability Organization’s review
procedure and the process for Regional
Reliability Organization approval of the
procedure.
R1.9. Determination, as appropriate, of
maintenance and testing requirements.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-012-1 R.1.7:
Covered by Requirements R5
and R6
PRC-012-1 R.1.8:
PRC-012-2 NERC Standards
Development Process
PRC-012-1 R.1.9:
Covered by Requirement R8
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
2
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
3
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R8. Each RAS-entity shall participate in performing a
functional test of each of its RAS to verify the overall RAS
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
4
Reliability Standard: PRC-012-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
performance and the proper operation of non-Protection
System components:
R2. The Regional Reliability Organization shall provide
affected Regional Reliability Organizations and NERC
with documentation of its RAS review procedure on
request (within 30 calendar days).
Retired P81
•
At least once every six full calendar years for all
RAS not designated as limited impact, or
•
At least once every twelve full calendar years
for all RAS designated as limited impact
N/A
Reliability Standard: PRC-013-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization that has a
Transmission Owner, Generator Owner, or
Distribution Provider with a RAS installed shall
maintain a RAS database. The database shall
include the following types of information:
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-013-1 R1:
Covered by Requirement R9
PRC-013-1 R1.1, R1.2, R1.3:
Covered by Requirement R9,
Attachment 3
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R9. Each Reliability Coordinator shall update a RAS
database containing, at a minimum, the information in
Attachment 3 at least once every twelve full calendar
months.
5
Reliability Standard: PRC-013-1
Translation to New
Standard or Other Action
Existing Requirement in Reliability Standard
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1.1. Design Objectives — Contingencies and
system conditions for which the RAS was
designed,
R1.2. Operation — The actions taken by the RAS in
response to Disturbance conditions, and
R1.3. Modeling — Information on detection logic
or relay settings that control operation of
the RAS.
R2. The Regional Reliability Organization shall provide to
affected Regional Reliability Organization(s) and
NERC documentation of its database or the
information therein on request (within 30 calendar
days).
Retired P81
N/A
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
R1. The Regional Reliability Organization shall assess the
operation, coordination, and effectiveness of all RAS
installed in its Region at least once every five years
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
Translation to New
Standard or Other Action
PRC-014-1 R1:
Covered by Requirement R4
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
6
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
for compliance with NERC Reliability Standards and
Regional criteria.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
7
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R2. The Regional Reliability Organization shall provide
either a summary report or a detailed report of its
assessment of the operation, coordination, and
effectiveness of all RAS installed in its Region to
affected Regional Reliability Organizations or NERC
on request (within 30 calendar days).
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-014-1 R2:
Covered by Requirement R4
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
8
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
9
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing
Reliability Coordinator and RAS-entity, and each
impacted Transmission Planner and Planning
Coordinator.
R3. The documentation of the Regional Reliability
Organization’s RAS assessment shall include the
following elements:
R3.1. Identification of group conducting the assessment
and the date the assessment was performed.
R3.2. Study years, system conditions, and contingencies
analyzed in the technical studies on which the
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-014-1 R3:
Covered by Requirement R4
PRC-014-1 R3.1 - R3.4:
Covered by Requirement R4
PRC-014-1 R3.5:
Covered by Requirement R6
R4. Each Planning Coordinator, at least once every five
full calendar years, shall:
4.1 Perform an evaluation of each RAS within its planning
area to determine whether:
4.1.1 The RAS mitigates the System condition(s) or
Contingency(ies) for which it was designed.
10
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
assessment is based and when those technical
studies were performed.
R3.3. Identification of RAS that were found not to
comply with NERC standards and Regional
Reliability Organization criteria.
R3.4. Discussion of any coordination problems found
between a RAS and other protection and control
systems.
R3.5. Provide corrective action plans for non-compliant
RAS.
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
4.1.2 The RAS avoids adverse interactions with other
RAS, and protection and control systems.
4.1.3 For limited impact RAS, the inadvertent
operation of the RAS or the failure of the RAS to
operate does not cause or contribute to BES
Cascading, uncontrolled separation, angular
instability, voltage instability, voltage collapse, or
unacceptably damped oscillations.
4.1.4 Except for “limited impact” RAS, the possible
inadvertent operation of the RAS, resulting from any
single RAS component malfunction satisfies all of the
following:
4.1.4.1 The BES shall remain stable.
4.1.4.2 Cascading shall not occur.
4.1.4.3 Applicable Facility Ratings shall not be
exceeded.
4.1.4.4 BES voltages shall be within postContingency voltage limits and postContingency voltage deviation limits as
established by the Transmission Planner and the
Planning Coordinator.
4.1.4.5 Transient voltage responses shall be
within acceptable limits as established by the
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
11
Reliability Standard: PRC-014-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
Transmission Planner and the Planning
Coordinator.
4.1.5 Except for limited impact RAS, a single
component failure in the RAS, when the RAS is
intended to operate does not prevent the BES from
meeting the same performance requirements
(defined in Reliability Standard TPL-001-4 or its
successor) as those required for the events and
conditions for which the RAS is designed.
4.2 Provide the results of the RAS evaluation including
any identified deficiencies to each reviewing Reliability
Coordinator and RAS-entity, and each impacted
Transmission Planner and Planning Coordinator.
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
12
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall maintain
a list of and provide data for existing and proposed
RAS as specified in Reliability Standard PRC-013-1
R1.
PRC-015-1 R1:
Covered by Requirement R1,
Attachment 1
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall have
evidence it reviewed new or functionally modified
RAS in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability
Standard PRC-012-1_R1 prior to being placed in
service.
PRC-015-1 R2:
Covered by Requirements R1,
Attachment 1; R2,
Attachment 2; and R3
R1. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS-entity shall
provide the information identified in Attachment 1 for
review to the Reliability Coordinator(s) where the RAS is
located.
R2. Each Reliability Coordinator that receives Attachment
1 information pursuant to Requirement R1 shall, within
four full calendar months of receipt, or on a mutually
agreed upon schedule, perform a review of the RAS in
accordance with Attachment 2, and provide written
feedback to each RAS-entity.
R3. Prior to placing a new or functionally modified RAS inservice or retiring an existing RAS, each RAS‐entity that
receives feedback from the reviewing Reliability
Coordinator(s) identifying issue(s) shall resolve each issue
to obtain approval of the RAS from each reviewing
Reliability Coordinator.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
Retired P81
N/A
13
Reliability Standard: PRC-015-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
documentation of RAS data and the results of
Studies that show compliance of new or functionally
modified RAS with NERC Reliability Standards and
Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on
request (within 30 calendar days).
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
14
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
R1. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall analyze
its RAS operations and maintain a record of all
misoperations in accordance with the Regional RAS
review procedure specified in Reliability Standard
PRC-012-1_R1.
Translation to New
Standard or Other Action
PRC-016-1 R1:
Covered by Requirement R5
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational performance
analysis that identified any deficiencies to its
reviewing Reliability Coordinator(s).
R2. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall take
corrective actions to avoid future misoperations.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
PRC-016-1 R2:
Covered by Requirements R6
and R7
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
15
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
R3. The Transmission Owner, Generator Owner, and
Distribution Provider that owns a RAS shall provide
documentation of the misoperation analyses and
the corrective action plans to its Regional Reliability
Organization and NERC on request (within 90
calendar days).
PRC-016-1 R3:
Covered by Requirements R5,
R6, and R7, Attachment 1
R5. Each RAS-entity, within 120 full calendar days of a
RAS operation or a failure of its RAS to operate when
expected, or on a mutually agreed upon schedule with its
reviewing Reliability Coordinator(s), shall:
5.1 Participate in analyzing the RAS operational
performance to determine whether:
5.1.1 The System events and/or conditions
appropriately triggered the RAS.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
16
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
5.1.2 The RAS responded as designed.
5.1.3 The RAS was effective in mitigating BES
performance issues it was designed to address.
5.1.4 The RAS operation resulted in any
unintended or adverse BES response.
5.2 Provide the results of RAS operational
performance analysis that identified any deficiencies
to its reviewing Reliability Coordinator(s).
R6. Each RAS-entity shall participate in developing a
Corrective Action Plan (CAP) and submit the CAP to its
reviewing Reliability Coordinator(s) within six full
calendar months of:
•
Being notified of a deficiency in its RAS pursuant to
Requirement R4, or
•
Notifying the Reliability Coordinator of a deficiency
pursuant to Requirement R5, Part 5.2, or
•
Identifying a deficiency in its RAS pursuant to
Requirement R8.
R7. Each RAS-entity shall, for each of its CAPs developed
pursuant to Requirement R6:
7.1 Implement the CAP.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
17
Reliability Standard: PRC-016-1
Existing Requirement in Reliability Standard
Translation to New
Standard or Other Action
New or revised Requirement in Proposed
Reliability Standard PRC-012-2
7.2 Update the CAP if actions or timetables
change.
7.3 Notify each reviewing Reliability Coordinator if
CAP actions or timetables change and when the
CAP is completed.
Mapping Document | February April 2016
Project 2010-05.3 Phase 2 3 of Protection Systems (RAS)
18
Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document | April 2016
2
Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
VRF and VSL Justification Document | April 2016
3
NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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4
Guideline (4) – 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.
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
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5
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to provide
the information identified in
Attachment 1 to each Reliability
Coordinator prior to placing a
new or functionally modified
RAS in service or retiring an
existing RAS in accordance with
Requirement R1.
6
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30 full calendar days
but less than or equal to 60 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60 full calendar days
but less than or equal to 90 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90 full calendar days.
OR
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
10
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in
service or retiring an existing
RAS in accordance with
Requirement R3.
N/A
14
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirement R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 90 full
calendar days.
OR
OR
The Planning Coordinator
The Planning Coordinator
performed the evaluation in
performed the evaluation in
accordance with Requirement
accordance with Requirement
R4, but failed to evaluate two or
R4, but failed to evaluate one of more of the Parts 4.1.1 through
the Parts 4.1.1 through 4.1.5.
4.1.5.
OR
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
receiving entities listed in Part
4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
less than or equal to 10 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 10 full calendar days
but less than or equal to 20 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 20 full calendar days
but less than or equal to 30 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 30 full calendar days.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1.1 through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
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VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10 full calendar days.
Moderate
High
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10 full calendar days but less
than or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20 full calendar days but less
than or equal to 30 full calendar
days.
Severe
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30 full calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐entity failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐entity implemented a
N/A
CAP in accordance with
Requirement R7, Part 7.1, but
failed to update the CAP (Part
7.2) if actions or timetables
changed, or failed to notify (Part
7.3) each of the reviewing
Reliability Coordinator(s) of the
updated CAP or completion of
the CAP.
ifications for PRC‐012‐2, Requirement R7
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High
N/A
Severe
The RAS‐entity failed to
implement a CAP in accordance
with Requirement R7, Part 7.1.
30
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 90 full
calendar days.
OR
The RAS‐entity failed to perform
the functional test for a RAS as
specified in Requirement R8.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30 full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30 full calendar days but less
than or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60 full calendar days but less
than or equal to 90 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than 90
full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
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FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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Violation Risk Factor and Violation Severity Level
Justification Document
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
This document provides the standard drafting team (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in PRC‐012‐2. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
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.
FERC Guidelines for Violation Risk Factors
Guideline (1) – 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. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:
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
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
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Guideline (2) – 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.
Guideline (3) – 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.
Guideline (4) – 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.
Guideline (5) – 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.
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NERC Criteria for Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
The performance or product
measured almost meets the full
intent of the requirement.
Moderate VSL
High VSL
The performance or product
The performance or product
measured meets the majority of measured does not meet the
the intent of the requirement. majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – 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.
Guideline (2) – 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.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
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Guideline (4) – 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.
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R1 relates to two of these
areas, specifically (i) protection systems and their coordination; and (ii) clearer criteria for operationally
critical facilities. Requirement R1 mandates that entities comply with a review process for new or modified
RAS or retirement of RAS. Among the elements of such reviews is the coordination between RAS and
other RAS and between RAS and protection and control systems. Requirement R1 also mandates that the
RAS‐entity provide the Reliability Coordinator relevant RAS information regarding the design and
implementation for each new or functionally modified RAS.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐012‐1, Requirement 1, Parts R1.1 – R1.5
which specifies attributes of the RRO process to review RAS (R1.1), provision of pertinent RAS data (R1.2),
dependability (R1.3) and security (R1.4) of design, and coordination with other RAS and protection
systems (R1.5), and has a Medium VRF.
FERC VRF G4 Discussion
A medium VRF is appropriate for this requirement because failure of an entity to submit Attachment 1
information to the responsible Reliability Coordinator for review prior to placing a new or modified RAS in
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5
VRF Justifications for PRC‐012‐2, Requirement R1
VRF for Requirement R1 is Medium
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
service or retiring an existing RAS could introduce risks to the Bulk Electric System. However, a violation of
this requirement, because it is in a planning time frame, is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, or to hinder restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R1
Lower
N/A
Moderate
N/A
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High
N/A
Severe
The RAS‐entity failed to provide
the information identified in
Attachment 1 to each Reliability
Coordinator prior to placing a
new or functionally modified
RAS in‐ service or retiring an
existing RAS in accordance with
Requirement R1.
6
VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐012‐1, Requirements R1.1 –
R1.5 which had four established Levels of Non‐Compliance. The requirement is binary with only a Severe
VSL so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R1
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R2 relates to one of these
areas, specifically, protection systems and their coordination. Requirement R2 mandates that Reliability
Coordinators review the RAS to determine if a RAS avoids adverse interactions with other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐014‐1, Requirement R1, which is related
to the review of RAS.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R2 because failure of a Reliability Coordinator to perform
the RAS reviews and identify potential risks presented by the RAS 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, a violation of this requirement, because it is in a planning time frame, is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
Bulk Electric System instability, separation, or cascading failures, or to hinder restoration to a normal
condition.
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9
VRF Justifications for PRC‐012‐2, Requirement R2
VRF for Requirement R2 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R2
Lower
Moderate
High
Severe
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
less than or equal to 30 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 30 full calendar days
but less than or equal to 60 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 60 full calendar days
but less than or equal to 90 full
calendar days.
The reviewing Reliability
Coordinator performed the
review and provided the written
feedback in accordance with
Requirement R2, but was late by
more than 90 full calendar days.
OR
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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The reviewing Reliability
Coordinator failed to perform
the review or provide feedback
in accordance with Requirement
R2.
10
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which also had four established Levels of Non‐Compliance. This requirement has VSLs comparable to the
established Levels of Non‐Compliance in that requirement, so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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11
VSL Justifications for PRC‐012‐2, Requirement R2
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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12
VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R3 relates to one of these
areas, specifically protection systems and their coordination. Requirement R3 requires the RAS‐entity to
address each identified reliability issue which includes the coordination between RAS and other RAS and
between RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐015‐0 Requirement R2 which requires
the entity to comply with the RRO procedure as defined in PRC‐012‐1 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of a RAS entity to address the reliability
issues identified during the RC review before placing it into service could introduce risks to the BES that
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, a violation of this requirement, because it
is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to
hinder restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R3
VRF for Requirement R3 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R3
Lower
N/A
Moderate
N/A
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High
Severe
The RAS‐entity failed to resolve
identified reliability issue(s) to
obtain approval from each
reviewing Reliability Coordinator
prior to placing a new or
functionally modified RAS in‐
service or retiring an existing
RAS in accordance with
Requirement R3.
N/A
14
VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐015‐0, Requirement R2
which has four established VSLs. This requirement is binary with only a Severe VSL so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: The language included in the Severe VSL is clear and unambiguous, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2b: N/A
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VSL Justifications for PRC‐012‐2, Requirement R3
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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16
VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R4 relates to one of these
areas, specifically protection systems and their coordination. Requirement R4 mandates that entities
perform periodic evaluations of each RAS to ensure that changes in System conditions have not changed
the effectiveness of the RAS to mitigate the events or System conditions for which it was designed.
Requirement R4 incorporates all actions necessary to determine if a RAS avoids adverse interactions with
other RAS and protection and control systems
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirement R3 which requires
the assessment of the effectiveness of UVLS Programs.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R4 because failure to perform the periodic evaluation could
allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement, because it is in a planning
time frame, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
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VRF Justifications for PRC‐012‐2, Requirement R4
VRF for Requirement R4 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by less than or equal to
30 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The Planning Coordinator
performed the evaluation as
specified in Requirement R4, but
was late by more than 90 full
calendar days.
OR
OR
The Planning Coordinator
The Planning Coordinator
performed the evaluation in
performed the evaluation in
accordance with Requirement
accordance with Requirement
R4, but failed to evaluate two or
R4, but failed to evaluate one of more of the Parts 4.1.1 through
the Parts 4.1.1 through 4.1.5.
4.1.5.
OR
The Planning Coordinator
performed the evaluation in
accordance with Requirement
R4, but failed to provide the
results to one or more of the
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VSLs for PRC‐012‐2, Requirement R4
Lower
Moderate
High
Severe
receiving entities listed in Part
4.2.
OR
The Planning Coordinator failed
to perform the evaluation in
accordance with Requirement
R4.
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐014‐0, Requirement R1
which has four established Levels of Non‐Compliance. This requirement has comparable VSLs so there is
no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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19
VSL Justifications for PRC‐012‐2, Requirement R4
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R4
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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20
VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
NERC VRF Discussion
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R5 relates to one of these
areas, specifically protection systems and their coordination. Requirement R5 mandates that entities
perform RAS operational performance analysis to verify that the RAS operation and the resulting System
performance was consistent with the Contingency events or System conditions for which it was designed.
Requirement R5 incorporates all actions necessary to identify coordination issues between RAS and other
RAS and between RAS and protection and control systems.
FERC VRF G2 Discussion
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
Guideline 2‐ Consistency
within a Reliability Standard conflict.
FERC VRF G3 Discussion
This requirement is consistent with NERC Reliability Standard PRC‐010‐2, Requirements R4 which requires
evaluation of the UVLS Program performance during a voltage excursion event.
Guideline 3‐ Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for Requirement R5 because failure to perform the RAS operational
performance analysis could allow RAS with diminished effectiveness to go undetected which 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. However, a violation of this requirement,
because it is in a planning time frame, is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures,
or to hinder restoration to a normal condition.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VRF Justifications for PRC‐012‐2, Requirement R5
VRF for Requirement R5 is Medium
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
less than or equal to 10 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 10 full calendar days
but less than or equal to 20 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 20 full calendar days
but less than or equal to 30 full
calendar days.
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but was late by
more than 30 full calendar days.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address one of the Parts 5.1.1
through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
address two or more of the
Parts 5.1.1 through 5.1.4.
OR
The RAS‐entity performed the
analysis in accordance with
Requirement R5, but failed to
provide the results (Part 5.2) to
one or more of the reviewing
Reliability Coordinator(s).
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VSLs for PRC‐012‐2, Requirement R5
Lower
Moderate
High
Severe
OR
The RAS‐entity failed to perform
the analysis in accordance with
Requirement R5
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0.1, Requirement R1,
and PRC‐012‐1, Requirement R1.7, which have four established Levels of Non‐Compliance. This
requirement has comparable VSLs so there is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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23
VSL Justifications for PRC‐012‐2, Requirement R5
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R5
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R6 addresses one of these
areas, specifically protection systems and their coordination. CAPs establish mitigation plans and
timetable to address deficiencies that could cause adverse interactions between RAS and other RAS and
protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because the failure of an entity to develop a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R6
VRF for Requirement R6 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
VSLs for PRC‐012‐2, Requirement R6
Lower
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by less than or
equal to 10 full calendar days.
Moderate
High
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
10 full calendar days but less
than or equal to 20 full calendar
days.
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
20 full calendar days but less
than or equal to 30 full calendar
days.
Severe
The RAS‐entity developed a
Corrective Action Plan and
submitted it to its reviewing
Reliability Coordinator(s) in
accordance with Requirement
R6, but was late by more than
30 full calendar days.
OR
The RAS‐entity developed a
Corrective Action Plan but failed
to submit it to one or more of its
reviewing Reliability
Coordinator(s) in accordance
with Requirement R6.
OR
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VSLs for PRC‐012‐2, Requirement R6
Lower
Moderate
High
Severe
The RAS‐entity failed to develop
a Corrective Action Plan in
accordance with Requirement
R6.
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirements R2 and
R3, and has VSLs comparable to the established Levels of Non‐Compliance in those requirements, so there
is no 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: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R6
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R6
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
NERC VRF Discussion
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R7 relates to one of these
areas, specifically protection systems and their coordination. Implemented CAPs address deficiencies that
could cause adverse interactions between RAS and other RAS and protection and control systems.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐016‐0, Requirements R2 and R3 which
require a RAS‐owner take corrective actions to avoid future misoperations and provide documentation of
the corrective action plans to the RRO.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A medium VRF is appropriate for this requirement because failure of an entity to implement a Corrective
Action Plan allows identified risks due to a deficiency in a RAS to remain unmitigated which 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, a violation of this requirement, because it is in a
planning time frame and Reliability Coordinators will mandate modified operating limits to maintain BES
reliability, is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
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VRF Justifications for PRC‐012‐2, Requirement R7
VRF for Requirement R7 is Medium
preparations, to lead to Bulk Electric System instability, separation, or cascading failures, or to hinder
restoration to a normal condition.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, does not co‐mingle obligations.
VSLs for PRC‐012‐2, Requirement R7
Lower
Moderate
The RAS‐entity implemented a
N/A
CAP in accordance with
Requirement R7, Part 7.1, but
failed to update the CAP (Part
7.2) if actions or timetables
changed, or failed to notify (Part
7.3) each of the reviewing
Reliability Coordinator(s) of the
updated CAP or completion of
the CAP.
ifications for PRC‐012‐2, Requirement R7
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High
N/A
Severe
The RAS‐entity failed to
implement a CAP in accordance
with Requirement R7, Part 7.1.
30
VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐016‐0, Requirement R2 and
has VSLs comparable to the established Levels of Non‐Compliance in that requirement, so there is no
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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the Lower and Severe VSLs is clear and unambiguous, thereby
supporting uniformity and consistency in the determination of similar penalties for similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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VSL Justifications for PRC‐012‐2, Requirement R7
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
NERC VRF Discussion
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R8 has interactions in three of
these areas, specifically (i) protection systems and their coordination, (ii) communication protocol and
facilities, and (iii) appropriate use of transmission loading relief. RAS interactions occur with protection
systems, utilize communication protocols and facilities for proper functioning, and are often used for
transmission loading relief.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements, so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with NERC Reliability Standard PRC‐005‐3, Requirement R3 which requires
the maintenance of Protection System Components and has a VRF of High.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A High VRF is appropriate for this Requirement since failure to perform functional testing may allow latent
failures to persist in a RAS. These latent failures could result in an unintended operation or a failure to
operate, either of which could directly 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. For these reasons, the requirement meets the NERC criteria
for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
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33
VRF Justifications for PRC‐012‐2, Requirement R8
VRF for Requirement R8 is High
mingle More than One
Obligation
VSLs for PRC‐012‐2, Requirement R8
Lower
Moderate
High
Severe
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by less than or equal to
30 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 30 full
calendar days but less than or
equal to 60 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 60 full
calendar days but less than or
equal to 90 full calendar days.
The RAS‐entity performed the
functional test for a RAS as
specified in Requirement R8, but
was late by more than 90 full
calendar days.
OR
The RAS‐entity failed to perform
the functional test for a RAS as
specified in Requirement R8.
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34
VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
While this requirement is new, it incorporates the reliability objectives of PRC‐017‐0, Requirements R1 and
R2, which had VSLs of Lower, Moderate, High, and Severe. This requirement has VSLs comparable to the
established VSLs so there is no 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 Assignments
that Contain Ambiguous
Language
Guideline 2a: N/A
Guideline 2b: The language included in the VSLs is clear and unambiguous, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
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VSL Justifications for PRC‐012‐2, Requirement R8
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
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VRF Justifications for PRC‐012‐2, Requirement R9
VRF for Requirement R9 is Lower
NERC VRF Discussion
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G1 Discussion
Guideline 1‐ Consistency
with Blackout Report
In the VSL Order, FERC identified twelve critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk‐Power System. Requirement R9 does not address any of the
identified areas; therefore, the FERC VRF G1 Discussion is not applicable.
FERC VRF G2 Discussion
Guideline 2‐ Consistency
within a Reliability Standard
This requirement does not use sub‐requirements so only one VRF was assigned. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency
among Reliability Standards
This requirement is consistent with PRC‐010‐2 Requirement R6 and PRC‐006‐1 Requirement R6, which
have an approved VRF of Lower.
FERC VRF G4 Discussion
Guideline 4‐ Consistency
with NERC Definitions of
VRFs
A Lower VRF is appropriate for this requirement because the failure of an entity to update the RAS
database, 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.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of
Requirements that Co‐
mingle More than One
Obligation
This requirement has only one reliability objective; therefore, this requirement does not co‐mingle
obligations.
Project 2010‐05.3 Phase 3 of Protection Systems: Remedial Action Schemes
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VSLs for PRC‐012‐2, Requirement R9
Lower
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by less than or
equal to 30 full calendar days.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
Moderate
High
Severe
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
30 full calendar days but less
than or equal to 60 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9, but was late by more than
60 full calendar days but less
than or equal to 90 full calendar
days.
The Reliability Coordinator
updated the RAS database in
accordance with Requirement
R9 but was late by more than 90
full calendar days.
OR
The Reliability Coordinator failed
to update the RAS database in
accordance with Requirement
R9.
VSL Justifications for PRC‐012‐2, Requirement R9
While this requirement is new, it incorporates the reliability objectives of PRC‐013‐0, Requirement R1 and
has VSLs comparable to the established Levels of Non‐Compliance of that requirements, so there is no
consequence of lowering the current level of compliance.
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FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VSL Justifications for PRC‐012‐2, Requirement R9
Guideline 2a: N/A
Guideline 2b: The language included in the Lower, Moderate, High, and Severe VSLs is clear and
unambiguous, thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
The VSL uses similar language to that used in the associated requirement and is therefore consistent with
the requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The VSL is based upon a single violation, not a cumulative number of violations.The VSL uses similar
language to that used in the associated requirement and is therefore consistent with the requirement.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
ViolationsFERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
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Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
April 2016
Table of Contents
Question & Answer for PRC-012-2 .............................................................................................................................2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ............................2
2. Why is the five year evaluation of Requirement R4 assigned to the Planning Coordinator? .............................2
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ..........3
4. Why do RAS need to be reviewed and approved by a group other than the RAS-entity? .................................3
5. What is required for RAS “single component failure” and why? ........................................................................3
6. What is required for RAS “inadvertent operation” and why? ............................................................................4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ..............................................................................................................................................................5
8. Why are RAS classifications not recognized in the standard? ............................................................................5
9. What constitutes a functional modification of a RAS? .......................................................................................6
Attachment A – Project Roster…………………………………………………………………………………………………………………………….7
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
Question & Answer | April 2016
1
Question & Answer for PRC-012-2
The Project 2010-05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC-012-2.
1.
Why is the Remedial Action Scheme (RAS) review assigned to the
Reliability Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk-Power System. The NERC white paper suggested
Reliability Coordinators (RCs) and Planning Coordinators (PCs) for RAS-review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best-suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. The Wide Area purview better facilitates
the evaluation of interactions among separate RAS, as well as interactions among RAS and other
protection and control systems. The selection of the RC also minimizes the possibility of a conflict
of interest that could exist because of business relationships among the RAS-entity, Planning
Coordinator, Transmission Planner, or other entities involved in the planning or implementation
of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain
objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2.
Why is the five year evaluation of Requirement R4 assigned to the
Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least once every five full
calendar years to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
2
3.
Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP-1-3 Requirement R13 requires Balancing Authorities (BA) and Transmission Operators (TOP)
to perform operational reliability assessments (e.g., real time contingency analysis (RTCA), dayahead, seasonal) that include data describing new or degraded RAS. In addition, IRO-005-4
requires RCs to share any pertinent data, such as data from RAS, with potentially affected BAs
and TOPs. Operating horizon assessments that include RAS are already required by other
standards, so an additional requirement duplicating that effort is not necessary.
TPL-001-4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near-term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short-term (annual) planning horizon assessments are already
required by the TPL-001-4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS-entities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why?
The existing PRC-012-1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.5 and
Attachment 1 of PRC-012-2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL-001-4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
•
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
3
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
•
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
•
Using alternative automatic actions to back up failures of single RAS components.
•
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re-dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC-012-2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review processes and designated as
Type III in NPCC or Local Area Protection Scheme (LAPS) in WECC will be recognized as limited
impact. When appropriate, new or functionally modified RAS implemented after the effective
date of this standard will be designated as limited impact by the Reliability Coordinator during
the RAS review process. Limited impact schemes are not subject to the single component failure
aspect of Requirement R4, Part 4.1.5.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC-012-1 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the contingency for which
it was designed and not exceed TPL-003-0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.4 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL-001-4 or for System conditions
not defined in TPL-001-4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.4.1 – 4.1.4.5, which are the
performance requirements common to all planning events P0–P7.
Within the RAS review process of PRC-012-2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
4
date of this standard that has been through the regional review processes and designated as
Type III in NPCC or LAPS in WECC will be recognized as limited impact. When appropriate, new or
functionally modified RAS implemented after the effective date of this standard will be
designated as limited impact by the Reliability Coordinator in conjunction with the RAS review
process. Limited impact schemes are not subject to the single component malfunction aspect of
Requirement R4, Part 4.1.4.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific System configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post-Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS-SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC-012-1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.5 and Attachment 1, item III.4
of PRC-012-2 that relates to single component failure; consequently, there is no need to have a
formal classification for this purpose.
Similarly, the standard drafting team concluded that the SPCS-SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC012-1, and problematic due to the difficulty of drawing a universally satisfactory delineation in
generally worded classification criteria. Within the RAS review process of PRC-012-2, there is a
provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation,
angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the regional
review processes and designated as Type III in NPCC or LAPS in WECC will be recognized as
limited impact. When appropriate, new or functionally modified RAS implemented after the
effective date of this standard will be designated as limited impact by the Reliability Coordinator
in conjunction with the RAS review process.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
5
9.
What constitutes a functional modification of a RAS?
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of
existing components
• Changes to RAS logic beyond correcting existing errors
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS-entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor that carries RAS communication when such changes may be
important to the timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component, or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation logic.
The Supplemental Material section of Reliability Standard PRC-012-2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
6
Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles-Eric Langlois
Hydro-Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | April 2016
7
Reliability Standard PRC-012-2
Remedial Action Schemes
Question & Answer Document
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
February April 2016
Table of Contents
Question & Answer for PRC-012-2 .............................................................................................................................2
1. Why is the Remedial Action Scheme (RAS) review assigned to the Reliability Coordinator? ............................2
2. Why is the five year evaluation of Requirement R4 assigned to the Planning Coordinator? .............................2
3. Why is the Planning Coordinator not required to perform an annual evaluation of RAS performance? ..........3
4. Why do RAS need to be reviewed and approved by a group other than the RAS-entity? .................................3
5. What is required for RAS “single component failure” and why? ........................................................................3
6. What is required for RAS “inadvertent operation” and why? ............................................................................4
7. What is meant by RAS adverse interaction or coordination with other RAS and protection and control
systems? ..............................................................................................................................................................5
8. Why are RAS classifications not recognized in the standard? ............................................................................5
9. What constitutes a functional modification of a RAS? .......................................................................................6
Attachment A – Project Roster…………………………………………………………………………………………………………………………….7
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes
Question & Answer | February April 2016
1
Question & Answer for PRC-012-2
The Project 2010-05.3 Phase 3 of Special Protection Systems: Remedial Action Schemes (RAS) standard
drafting team (SDT) developed this Question & Answer document to explain the key concepts
incorporated into Reliability Standard PRC-012-2.
1.
Why is the Remedial Action Scheme (RAS) review assigned to the
Reliability Coordinator?
NERC Reliability Standards require accountability; consequently, they must be applicable to
specific users, owners, and operators of the Bulk-Power System. The NERC white paper suggested
Reliability Coordinators (RCs) and Planning Coordinators (PCs) for RAS-review responsibility. The
SDT considered the suggestion and ultimately chose the Reliability Coordinator because of the RC
has the widest possible view of the System of any operating or planning entity. Some Regions
have as many as 30 PCs for one RC while other Regions or other System footprints have a single
PC and RC for the same area. Overall, there are 16 RCs and approximately 80 PCs in North
America. The large RC geographic oversight will minimize fragmentation of the regional reviews
currently administered by the Regions and promote continuity.
The RC is the best-suited functional entity to perform the Remedial Action Scheme (RAS) review
because the RC has the widest area reliability perspective of all functional entities and an
awareness of reliability issues in neighboring RC Areas. The Wide Area purview better facilitates
the evaluation of interactions among separate RAS, as well as interactions among RAS and other
protection and control systems. The selection of the RC also minimizes the possibility of a conflict
of interest that could exist because of business relationships among the RAS-entity, Planning
Coordinator, Transmission Planner, or other entities involved in the planning or implementation
of a RAS. The RC is also less likely to be a stakeholder in any given RAS and can therefore maintain
objective independence.
The RC is not expected to possess more information or ability than anticipated by their functional
registration as designated by NERC. The NERC Functional Model is a guideline for the
development of standards and their applicability and does not contain compliance requirements.
If Reliability Standards address functions that are not described in the model, the Reliability
Standard requirements take precedence over the Functional Model. For further reference, please
see the Introduction section of NERC’s Reliability Functional Model, Version 5, November 2009.
The RC may request aid in RAS reviews from other parties such as the Planning Coordinator(s) or
regional technical groups; however, the RC retains responsibility for compliance with the
requirement.
2.
Why is the five year evaluation of Requirement R4 assigned to the
Planning Coordinator?
Requirement R4 states that an evaluation of each RAS must be done at least once every five full
calendar years to verify the continued effectiveness and coordination of the RAS, its inadvertent
operation performance, and the performance for a single component failure. The items that must
be addressed in the evaluations include: 1) RAS mitigation of the System condition(s) or event(s)
for which it was designed; 2) RAS avoidance of adverse interactions with other RAS and with
protection and control systems; 3) the impact of inadvertent operation; and 4) the impact of a
single component failure. The evaluation of these items involves modeling and studying the
interconnected transmission system, similar to the planning analyses performed by PCs.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February April 20165
2
3.
Why is the Planning Coordinator not required to perform an annual
evaluation of RAS performance?
TOP-1-3 Requirement R13 requires Balancing Authorities (BA) and Transmission Operators (TOP)
to perform operational reliability assessments (e.g., real time contingency analysis (RTCA), dayahead, seasonal) that include data describing new or degraded RAS. In addition, IRO-005-4
requires RCs to share any pertinent data, such as data from RAS, with potentially affected BAs
and TOPs. Operating horizon assessments that include RAS are already required by other
standards, so an additional requirement duplicating that effort is not necessary.
TPL-001-4 Requirement R2 also requires TPs and PCs to perform annual planning assessments of
the near-term transmission planning horizon. Requirement R2 Part 2.7.1 acknowledges that new,
modified, or removed RAS may be part of a corrective action plan (CAP) used to fulfill Table 1
performance requirements. Short-term (annual) planning horizon assessments are already
required by the TPL-001-4 standard, including RAS, so an additional requirement duplicating that
effort is not necessary.
4.
Why do RAS need to be reviewed and approved by a group other
than the RAS-entity?
RAS are unique and customized assemblages of protection and control equipment. As such, they
have a potential to introduce reliability risks to the Bulk Electric System (BES) if not carefully
planned, designed, and installed. A RAS may be installed to address a reliability issue or to
achieve an economic or operational advantage, and could introduce reliability risks that may not
be apparent to the RAS-entities. An independent review and approval is an objective and
effective means of identifying risks and recommending RAS modifications when necessary.
5.
What is required for RAS “single component failure” and why?
The existing PRC-012-1 Requirement 1 R1.3 states “Requirements to demonstrate that the RAS
shall be designed so that a single RAS component failure, when the RAS was intended to operate,
does not prevent the interconnected transmission system from meeting the performance
requirements defined in Reliability Standards TPL-001-0, TPL-002-0, and TPL-003-0.” If a RAS is
installed to satisfy the performance requirements of a NERC Reliability Standard, it is necessary
that its operation, under the conditions and events for which it is designed to operate, be
ensured in the operational realm as well as in the planning realm. Requirement R4, Part 4.1.5 and
Attachment 1 of PRC-012-2 reaffirms this objective by stating: “a single component failure in the
RAS, when the RAS is intended to operate, does not prevent the BES from meeting the same
performance requirements (defined in Reliability Standard TPL-001-4 or its successor) as those
required for the events and conditions for which the RAS was designed.”
Acceptable methods for achieving this BES performance objective include the following:
•
Providing redundancy of RAS components listed below:
o Protective or auxiliary relays used by the RAS
o Communications systems necessary for correct operation of the RAS
o Sensing devices used to measure electrical quantities used by the RAS
o Station dc supply associated with RAS functions
o Control circuitry associated with RAS functions through the trip coil(s) of the circuit
breakers or other interrupting devices
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February April 20165
3
o Computers or programmable logic devices used to analyze information and provide RAS
operational output
•
Arming more load or generation than necessary such that failure of the RAS to drop a portion
of load or generation would not be an issue if tripping the total armed amount of load or
generation does not cause other adverse impacts to reliability.
•
Using alternative automatic actions to back up failures of single RAS components.
•
Manual backup operations, using planned System adjustments such as transmission
configuration changes and re-dispatch of generation if such adjustments are executable
within the time duration applicable to the facility ratings.
When a component failure occurs, the resulting BES performance will depend on what RAS
component failed and how critical it is to the functions of the RAS. This risk can only be evaluated
on an individual basis through the review process.
Within the RAS review process of PRC-012-2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
date of this standard that has been through the regional review processes and designated as
Type 3 III in NPCC or Local Area Protection Scheme (LAPS) in WECC will be recognized as limited
impact. When appropriate, new or functionally modified RAS implemented after the effective
date of this standard will be designated as limited impact by the Reliability Coordinator during
the RAS review process. Limited impact schemes are not subject to the single component failure
aspect of Requirement R4, Part 4.1.5.
6.
What is required for RAS “inadvertent operation” and why?
The possibility of inadvertent operation of a RAS during System events and conditions that are
not intended to activate its operation must be considered. The existing PRC-012-1 Requirement
1, R1.4 states that the inadvertent operation of a RAS shall meet the same performance
requirement (TPL-001-0, TPL-002-0, and TPL-003-0) as that required of the contingency for which
it was designed and not exceed TPL-003-0. The drafting team clarified that the inadvertent
operation to be considered would only be caused by the malfunction of a single RAS component.
It is therefore possible to design security against inadvertent operation into the RAS logic and
hardware such that a malfunction of any one RAS component would be unable to cause a RAS
inadvertent operation, or might limit inadvertent operation of a RAS in part.
The intent of Requirement R4, Part 4.1.4 is to require a RAS to be designed so that its whole or
partial inadvertent operation due to a single component malfunction does not prevent the
System from meeting the performance requirements for the same contingency for which the RAS
was designed. If the RAS was installed for an extreme event in TPL-001-4 or for System conditions
not defined in TPL-001-4, inadvertent operation must not prevent the System from meeting the
performance requirements specified in Requirement R4, Parts 4.1.4.1 – 4.1.4.5, which are the
performance requirements common to all planning events P0–P7.
Within the RAS review process of PRC-012-2, there is a provision that RAS can be designated as
“limited impact” if the RAS cannot, by inadvertent operation or failure to operate, cause or
contribute to BES Cascading, uncontrolled separation, angular instability, voltage instability,
voltage collapse, or unacceptably damped oscillations. A RAS implemented prior to the effective
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February April 20165
4
date of this standard that has been through the regional review processes and designated as
Type 3 III in NPCC or LAPS in WECC will be recognized as limited impact. When appropriate, new
or functionally modified RAS implemented after the effective date of this standard will be
designated as limited impact by the Reliability Coordinator in conjunction with the RAS review
process. Limited impact schemes are not subject to the single component malfunction aspect of
Requirement R4, Part 4.1.4.
7.
What is meant by RAS adverse interaction or coordination with
other RAS and protection and control systems?
RAS are complex schemes that typically take actions to trip load or generation or reconfigure the
System. Many RAS depend on sensing specific System configurations to determine whether they
need to arm or take action. Though unusual, overlapping actions among RAS would have the
potential to result in Cascading unless they were coordinated. Similarly, RAS operation can
change System configuration and available fault duty, which can affect coordination with distance
relay overcurrent (“fault detector”) supervision and ground overcurrent protection. A third
coordination example is RAS operational timing that must coordinate with automatic reclosing on
a faulted line. Many RAS are intended to mitigate post-Contingency overloads. A short
coordinating delay up to a few seconds is required to avoid initiating action until a System Fault
can be detected and cleared by Protection System action. A delay of several minutes may be
acceptable as long as it is compatible with the thermal characteristics of the overloaded
equipment.
8.
Why are RAS classifications not recognized in the standard?
RAS classification was suggested in the SPCS-SAMS report as a means to differentiate the
reliability risks between planning and extreme RAS for continuity with PRC-012-1 R1.3; however,
the standard drafting team concluded the classification is unnecessary. The distinction between
planning and extreme RAS is captured in Requirement R4, Part 4.1.5 and Attachment 1, item III.4
of PRC-012-2 that relates to single component failure; consequently, there is no need to have a
formal classification for this purpose.
Similarly, the standard drafting team concluded that the SPCS-SAMS distinction between
significant and limited RAS was unnecessary for the purpose of maintaining continuity with PRC012-1, and problematic due to the difficulty of drawing a universally satisfactory delineation in
generally worded classification criteria. Within the RAS review process of PRC-012-2, there is a
provision that RAS can be designated as “limited impact” if the RAS cannot, by inadvertent
operation or failure to operate, cause or contribute to BES Cascading, uncontrolled separation,
angular instability, voltage instability, voltage collapse, or unacceptably damped oscillations. A
RAS implemented prior to the effective date of this standard that has been through the regional
review processes and designated as Type 3 III in NPCC or LAPS in WECC will be recognized as
limited impact. When appropriate, new or functionally modified RAS implemented after the
effective date of this standard will be designated as limited impact by the Reliability Coordinator
in conjunction with the RAS review process.
Some Regions classify RAS to prescribe RAS design and review requirements specific to the
Region. Avoiding RAS classifications in the proposed standard makes it possible to retain Regional
Entity classifications and associated criteria without overlap and confusion.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February April 20165
5
9.
What constitutes a functional modification of a RAS?
A functional modification to a RAS consists of any of the following:
• Changes to System conditions or contingencies monitored by the RAS
• Changes to the actions the RAS is designed to initiate
• Changes to RAS hardware beyond in-kind replacement; i.e., match the original functionality of
existing components
• Changes to RAS logic beyond correcting existing errors
• Changes to redundancy levels (addition or removal)
RAS retirement or removal is a form of RAS functional modification. A RAS-entity must submit the
RAS data specified in the “RAS Retirement” section of Attachment 1.
The following are examples of RAS functional changes:
1. Replacement of a RAS field device if the replacement requires changes in device custom logic.
2. Changes to the telecommunication infrastructure or communication facility, such as the
replacement of a T1 multiplexor that carries RAS communication when such changes may be
important to the timing of a RAS.
3. The addition or removal of mitigation actions within a RAS component.
4. The addition or removal of contingencies or System conditions for which a RAS was designed
to operate.
5. Changes to the RAS design to account for station bus configuration changes.
The following examples are not considered RAS functional changes:
1. The replacement of a failed RAS component with an identical component, or a component
that uses the same functionality as the failed component.
2. A firmware upgrade of a RAS component if the change does not require changes in the RAS
implementation logic.
The Supplemental Material section of Reliability Standard PRC-012-2 also includes several
additional examples of RAS changes that do and do not constitute functional modifications.
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February April 20165
6
Attachment A – Project Roster
Project 2010-05.3 – Remedial Action Schemes
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Member
Amos Ang
Southern California Edison
Member
Alan Engelmann
ComEd / Exelon
Member
Davis Erwin
Pacific Gas and Electric
Member
Sharma Kolluri
Entergy
Member
Charles-Eric Langlois
Hydro-Quebec TransEnergie
Member
Robert J. O'Keefe
American Electric Power
Member
Hari Singh
Xcel Energy
NERC Staff
Al McMeekin (Standards Developer)
NERC
NERC Staff
Lacey Ourso (Standards Developer)
NERC
NERC Staff
Andrew Wills (Associate Counsel)
NERC
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action Schemes (RAS)
Question & Answer | February April 20165
7
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems: Remedial
Action Schemes (RAS)
PRC-012-2 and Definition of “Special Protection System”
Final Ballots Open through April 29, 2016
Now Available
Final ballots for PRC-012-2 – Remedial Action Schemes and the Revised Definition of “Special Protection
System” are open through 8 p.m. Eastern, Friday, April 29, 2016.
Balloting
In the final ballot, votes are counted by exception. Only members of the ballot pools may cast a vote. All
ballot pool members may change their previously cast vote. A ballot pool member who failed to vote
during the previous ballot period may vote in the final ballot period. If a ballot pool member does not
participate in the final ballot, the member’s vote from the previous ballot will be carried over as their
vote in the final ballot.
Members of the ballot pools associated with this project may log in and submit their votes for the
standard and definition here. If you experience any difficulties using the Standards Balloting &
Commenting System (SBS), contact Wendy Muller.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
The voting results for the standard and definition will be posted and announced after the ballots close. If
approved, the standard and definition will be submitted to the Board of Trustees for adoption and then
filed with the appropriate regulatory authorities.
Standards Development Process
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-05.3 Phase 3 of Protection Systems:
Remedial Action Schemes (RAS)
PRC-012-2 and Definition of “Special Protection System”
Final Ballot Results
Now Available
Final ballots for PRC-012-2 – Remedial Action Schemes and the Revised Definition of “Special Protection
System” concluded 8 p.m. Eastern, Friday, April 29, 2016.
The voting statistics are listed below, and the Ballot Results page provides detailed results for the ballots.
Quorum / Approval
PRC-012-2
81.19% / 80.36%
Definition of
“Special Protection System”
87.15% / 93.43%
Next Steps
The standard and definition will be submitted to the Board of Trustees for adoption and then filed with
the appropriate regulatory authorities.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Al McMeekin (via email), or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Exhibit I
Standard Drafting Team Roster
Standard Drafting Team Roster
Project 2010-05.3 Phase 3 of Protection Systems: Remedial Action
Schemes (RAS)
Participant
Entity
Chair
Gene Henneberg
NV Energy / Berkshire Hathaway Energy
Vice Chair
Bobby Jones
Southern Company
Members
Amos Ang
Southern California Edison
Alan Engelmann
ComEd / Exelon
Davis Erwin
Pacific Gas and Electric
Sharma Kolluri
Entergy
Charles-Eric Langlois
Hydro-Quebec TransEnergie
Robert J. O'Keefe
American Electric Power
Hari Singh
Xcel Energy
PMOS Liaison
Rod Kinard
Oncor Electric Delivery
NERC Staff
Al McMeekin – Senior Standards
Developer
North American Electric Reliability Corporation
Lacey Ourso – Standards Developer
(Support)
North American Electric Reliability Corporation
Andrew Wills – Associate Counsel
North American Electric Reliability Corporation
| File Type | application/pdf |
| Author | Brady Walker |
| File Modified | 2017-02-01 |
| File Created | 2016-08-05 |