RM16-22, NERC Petition (without Exhibits)

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 STANDARDS PRC-027-1 AND PER006-1 AND RETIREMENT OF PRC-001-1.1(ii)
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

Charles A. Berardesco
Senior Vice President and General Counsel
Shamai Elstein
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
202-400-3000
charles.berardesco@nerc.net
shamai.elstein@nerc.net
Counsel for the North American Electric
Reliability Corporation

September 2, 2016

TABLE OF CONTENTS
I.

EXECUTIVE SUMMARY .................................................................................................... 2

II.

NOTICES AND COMMUNICATIONS ................................................................................ 7

III. BACKGROUND .................................................................................................................... 7
A.

Regulatory Framework ..................................................................................................... 7

B.

NERC Reliability Standards Development Procedure ..................................................... 8

C.

Development of the Proposed Reliability Standards........................................................ 9

IV. JUSTIFICATION FOR APPROVAL................................................................................... 10

V.

A.

PER Reliability Standards and Retirement of Requirement R1 of PRC-001-1.1(ii) ..... 11

B.

PRC-027-1 and Retirement of Requirements R3 and R4 of PRC-001-1.1(ii) ............... 26

C.

Retirement of Requirements R2, R5 and R6 of PRC-001-1.1(ii) .................................. 42

D.

Resolution of Outstanding Commission Directives Related to PRC-001-1.1(ii) .......... 57

E.

Enforceability of the Proposed Reliability Standards .................................................... 60
EFFECTIVE DATE .............................................................................................................. 60

VI. CONCLUSION ..................................................................................................................... 61

Exhibit A

Proposed Reliability Standards and Definitions
Exhibit A-1 Proposed Reliability Standard PRC-027-1
Exhibit A-2 Proposed Reliability Standard PER-006-1
Exhibit A-3 Proposed Definitions

Exhibit B

Implementation Plans
Exhibit B-1 Implementation Plan for Project 2007‐06 System Protection
Coordination
Exhibit B-2 Implementation Plan for Project 2007-06.2 Phase 2 of System
Protection Coordination

Exhibit C

Order No. 672 Criteria

Exhibit D

Mapping Documents
Exhibit D-1 Mapping Document for Project 2007‐06 System Protection
Coordination
Exhibit D-2 Mapping Document for Project 2007-06.2 Phase 2 of System
Protection Coordination

Exhibit E

Evaluation of Proposed Definitions for Project 2007-06.2 – Phase 2 of System
Protection Coordination

Exhibit F

Analysis of Violation Risk Factors and Violation Severity Levels
i

TABLE OF CONTENTS
Exhibit F-1 Analysis of Violation Risk Factors and Violation Severity Levels
for Reliability Standard PRC-027-1
Exhibit F-2 Analysis of Violation Risk Factors and Violation Severity Levels
for Reliability Standard PER-006-1
Exhibit G

Summary of Development History and Record of Development
Exhibit G-1 Summary of Development History and Record of Development
for Project 2007‐06 System Protection Coordination
Exhibit G-2 Summary of Development History and Record of Development
for Project 2007-06.2 Phase 2 of System Protection Coordination

Exhibit H

Standard Drafting Team Rosters
Exhibit H-1 Standard Drafting Team Roster for Project 2007‐06 System
Protection Coordination
Exhibit H-2 Standard Drafting Team Roster for Project 2007-06.2 Phase 2 of
System Protection Coordination

ii

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 STANDARDS PRC-027-1 AND PER006-1 AND RETIREMENT OF PRC-001-1.1(ii)
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 submits for Commission
approval:
•

proposed Reliability Standards PRC-027-1 and PER-006-1 (Exhibit A);

•

proposed new and revised definitions to be incorporated into the Glossary of Terms Used
in NERC Reliability Standards (“NERC Glossary”) for the following terms: (1) Protection
System Coordination Study; (2) Operational Planning Analysis (“OPA”); and (3) Realtime Assessment (“RTA”) (Exhibit A);

•

the retirement of Reliability Standard PRC-001-1.1(ii);

•

the associated Implementation Plans (Exhibit B); and

•

the associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”)
(Exhibit F). 4

1

16 U.S.C. § 824o (2012).

2

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 FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).

4
Unless otherwise designated, all capitalized terms used herein 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.

1

As required by Section 39.5(a) of the Commission’s regulations, 5 this Petition presents the
technical basis and purpose of the proposed Reliability Standards and NERC Glossary definitions,
a summary of the development history (Exhibit G), and a demonstration that the proposed
Reliability Standards and definitions meet the criteria identified by the Commission in Order No.
672 6 (Exhibit C). The NERC Board of Trustees (“Board”) adopted proposed Reliability Standard
PRC-027-1 and the definition of Protection System Coordination Study on November 5, 2015, and
proposed Reliability Standard PER-006-1 and the modified definitions of OPA and RTA on
August 11, 2016.
I.

EXECUTIVE SUMMARY
The purpose of the proposed Reliability Standards and the proposed NERC Glossary

definitions is to: (1) maintain the coordination of Protection Systems installed to detect and isolate
Faults on Bulk Electric System (“BES”) Elements, such that those Protection Systems operate in
the intended sequence during Faults; and (2) require registered entities to provide training to their
relevant personnel on Protection Systems and Remedial Action Schemes (“RAS”) to help ensure
that the BES is reliably operated. The reliable and coordinated operation of Protection Systems is
essential to Bulk Power System (“BPS”) reliability for the following reasons. Protection Systems
help maintain reliability by isolating faulted equipment, thereby reducing the risk of instability or
Cascading, and leaving the remainder of the BPS operational and more capable of withstanding a
future Contingency. In the event of a Fault, properly coordinated Protection Systems minimize
the number of BES Elements that are removed from service and protect equipment from damage.

5

18 C.F.R. § 39.5(a) (2016).

6

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).

2

System reliability is reduced or threatened if a Protection System can no longer perform as
designed because of a failure of its relays. Further, the functions, settings, and limitations of
Protection Systems are recognized and integrated in deriving System Operating Limits (“SOLs”)
and Interconnection Reliability Operating Limits (“IROLs”). 7
Issues related to the coordination of Protection Systems are currently addressed in
Reliability Standard PRC-001-1.1(ii), which includes the following six requirements:
•

Requirement R1 provides that “[e]ach Transmission Operator, Balancing Authority, and
Generator Operator shall be familiar with the purpose and limitations of Protection System
schemes applied in its area.”

•

Requirement R2 provides that Generator Operators and Transmission Operators shall
notify certain other entities of relay or equipment failures that reduce system reliability and
take corrective action as soon as possible.

•

Requirement R3 addresses the coordination of new protective systems and changes to
existing protective systems.

•

Requirement R4 provides that Transmission Operators must coordinate Protection Systems
on major transmission lines and interconnections with certain neighboring entities.

•

Requirement R5 requires Generator Operators and Transmission Operators to coordinate
changes in generation, transmission, load or operating conditions that could require
changes in the Protection Systems of others.

•

Requirement R6 requires Transmission Operators and Balancing Authorities to monitor the
status of each Special Protection System (“SPS”) in their area and notify affected entities
of any change in status.
As explained further below, NERC is proposing to retire Reliability Standard PRC-001-

1.1(ii).

The Requirements in PRC-001-1.1(ii) are being replaced by proposed Reliability

Standards PRC-027-1 and PER-006-1 and the proposed definitions, or are addressed by Reliability
Standards approved by the Commission since the effective date of PRC-001-1, as follows:

7

SOLs and IROLs are vital concepts in NERC’s Reliability Standards as they establish acceptable
performance criteria both pre- and post-contingency to maintain reliable Bulk Electric System operations.

3

PRC-001-1.1(ii) Requirement R1: Along with currently-effective Personnel Performance,
Training, and Qualifications (“PER”) Reliability Standards, proposed Reliability Standard PER006-1 and the proposed modifications to the definitions of OPA and RTA are designed to improve
upon and replace PRC-001-1.1(ii), Requirement R1 in addressing the reliability goal of requiring
Generator Operators, Balancing Authorities, and Transmission Operations to be “familiar with”
the purpose and limitations of Protection System schemes. Focusing on the certification and
training requirements in the PER group of Reliability Standards as the mechanism for ensuring
that the necessary personnel are familiar with the purpose and limitations of Protection System
schemes will provide more precise and auditable requirements to achieve the reliability objective
of Requirement R1 of PRC-001-1.1(ii). Currently-effective PER-005-2, Requirement R6 already
requires Generator Operators to provide training to their centrally-located dispatch personnel on
how their job functions impact BES reliability. Proposed PER-006-1 adds a requirement in the
PER standards that Generator Operators train their plant operating personnel on the operational
functionality of Protection Systems and RAS that affect the output of their generating Facilities. 8
For Transmission Operators and Balancing Authorities, the reliability goal of Requirement R1 is
addressed by the currently-effective certification and training requirements in PER-003-1 and
PER-005-2, respectively.
Additionally, the proposed modifications to the definitions of OPA and RTA further the
objective of PRC-001-1.1(ii), Requirement R1 by requiring that Transmission Operators, as well
as Reliability Coordinators, consider the functions and limitations of Protection Systems and RAS
when performing the OPAs and RTAs required under the Transmission Operations (“TOP”) and

8
The phrase “Protection System schemes” in PRC-001-1.1(ii), Requirement R1 maps to the NERC Glossary
terms “Protection Systems” and “Remedial Action Schemes,” as explained below.

4

Interconnection Reliability Operations and Coordination (“IRO”) group of Reliability Standards
to determine whether there are any actual or expected SOL or IROL exceedances.
PRC-001-1.1(ii) Requirement R2: The reliability goal of PRC-001-1.1(ii) Requirement R2
for Generator Operators and Transmission Operators to notify certain other entities of certain relay
or equipment failures and take corrective action as soon as possible is addressed in recently
approved Reliability Standards IRO-001-4, IRO‐008‐2, IRO‐010‐2, TOP‐001‐3, and TOP‐003‐3. 9
As discussed below, these standards collectively require, among others things, that (1) Reliability
Coordinators, Balancing Authorities, and Transmission Operators maintain reliability in their area
by their own actions or by directing the actions of others (e.g., taking corrective action in event of
relay or equipment failure), and (2) require other registered entities to provide Reliability
Coordinators and Transmission Operators with data or notifications under certain circumstances,
including notifications regarding the status or degradation of Protection Systems and SPS. 10
PRC-001-1.1(ii) Requirements R3 and R4: Proposed Reliability Standard PRC-027-1 is
designed to improve upon and replace Requirements R3 and R4 of PRC-001-1.1(ii) in addressing
the reliability objective of Protection System coordination. Proposed Reliability Standard PRC027-1 provides a clear set of Requirements that obligate applicable entities to (1) implement a
process for establishing and coordinating new or revised Protection System settings and (2)
periodically study Protection System settings that could be affected by incremental changes in

9

These Reliability Standards – along with IRO-002-4, IRO-014-3, IRO-017-1, and TOP-002-4 – were
approved in Order No. 817. Transmission Operations Reliability Standards and Interconnection Reliability
Operations and Coordination Reliability Standards, Order No. 817, 153 FERC ¶ 61,178, 80 Fed. Reg. 73977
(2015).
10

Per the Commission’s order approving the revised definition of SPS on June 23, 2016, SPS and RAS are
interchangeable terms. See N. Am. Elec. Reliability Corp., Docket No. RD16-5-000 (June 23, 2016) (unpublished
letter order). This Petition uses the NERC Glossary terms “RAS” or “SPS” depending on the language in the
Requirement the Petition is discussing. If the Petition is discussing a Requirement that uses RAS, for instance, the
Petition will refer to RAS when discussing that Requirement.

5

Fault current to ensure they continue to be appropriate (i.e., that the Protection System continues
to operate in the intended sequence during Faults).
PRC-001-1.1(ii) Requirement R5: The reliability objective of coordinating changes in
generation, transmission, load or operating conditions that could require changes in the Protection
Systems of others is now primarily addressed by Reliability Standard TOP-003-3, as well as
Reliability Standards TOP-001-3, TOP-002-4, IRO-008-2, IRO-010-2, and IRO-017-1, which
were developed since PRC-001-1.1(ii) went into effect. As discussed further below, these
Reliability Standards require coordination and analysis of changes in conditions that would
necessitate changes to the Protection Systems of others, amongst other actions.
PRC-001-1.1(ii) Requirement R6: The reliability objective of requiring Transmission
Operators and Balancing Authorities to monitor the status of each SPS in their area and notify
affected entities of any change in status is addressed in recently approved Reliability Standard
TOP-001-3 and TOP-003-3. Requirements R10 and R11 of TOP-001-3 create an affirmative
obligation for Transmission Operators and Balancing Authorities to monitor the status of SPS.
Pursuant to TOP-003-3, Transmission Operators and Balancing Authorities must provide
notifications regarding any change in Protection System status to other Transmission Operators
and Balancing Authorities.
In summary, the proposed Reliability Standards represent an improvement over currentlyeffective PRC-001-1.1(ii) and more effectively accomplish the reliability goals of ensuring that
appropriate personnel are trained on Protection Systems and that Protection System settings are
appropriately studied, coordinated, and monitored. For the reasons discussed herein, NERC
respectfully requests that the Commission approve the proposed Reliability Standards and NERC

6

Glossary definitions, and the proposed retirement of PRC-001-1.1(ii) as just, reasonable, not
unduly discriminatory, or preferential, and in the public interest.
II.

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

Shamai Elstein
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
202-400-3000
shamai.elstein@nerc.net

III.

Howard Gugel
Senior Director, Standards and Education
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
404-446-9693
howard.gugel@nerc.net

BACKGROUND
A.

Regulatory Framework

By enacting the Energy Policy Act of 2005, 11 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 duty of certifying an 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. 12 Section 215(d)(5) of the FPA
authorizes the Commission to order the ERO to submit a new or modified Reliability Standard. 13
Section 39.5(a) of the Commission’s regulations requires the ERO to file for Commission approval
each Reliability Standard that the ERO proposes should become mandatory and enforceable in the

11

16 U.S.C. § 824o (2012).

12

Id. § 824(b)(1).

13

Id. § 824o(d)(5).

7

United States, and each modification to a Reliability Standard that the ERO proposes to make
effective. 14
The Commission has 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. Pursuant to
Section 215(d)(2) of the FPA and Section 39.5(c) of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the content
of a Reliability Standard. 15
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 16 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 17 In its ERO
Certification Order, 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 and thus satisfies certain of the criteria for approving Reliability
Standards. The 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.

14

18 C.F.R. § 39.5(a) (2016).

15

16 U.S.C. § 824o(d)(2); 18 C.F.R. § 39.5(c)(1).

16

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).

17

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.

8

Further, a vote of stakeholders and adoption by the NERC Board is required before NERC submits
the Reliability Standard to the Commission for approval.
C.

Development of the Proposed Reliability Standards

As further described in Exhibit G hereto, proposed Reliability Standard PRC-027-1 and
the NERC Glossary term Protection System Coordination Study were developed as part of Project
2007-06 – System Protection Coordination to replace and improve upon Requirements R3 and R4
of PRC-001-1.1(ii). On September 11, 2015, the sixth draft of proposed Reliability Standard PRC027-1 and the definition for the new NERC Glossary term Protection System Coordination Study
received the requisite approval from the registered ballot body. A final ballot for the standard and
the definition concluded on October 14, 2015, with a ballot body approval of 80.94%. The NERC
Board adopted the standard and definition on November 5, 2015. 18
PER-006-1 and the revisions to the definitions of OPA and RTA were developed in the
second phase of that project, Project 2007-06.2 – Phase 2 of System Protection Coordination to
replace and improve upon Requirement R1 of PRC-001-1.1(ii). Project 2007-06.2 also addressed
the retirement of Requirements R2, R5, and R6 of PRC-001-1.1(ii). Proposed PER-006-1, the
revised definitions of OPA and RTA, and the retirement of PRC-001-1.1(ii), Requirements R2,
R5, and R6 received the requisite approval from the registered ballot body on April 25, 2016. Final
ballots for the standard, the definitions, and the retirements concluded on May 26, 2016, with ballot
body approvals of 82.52% (PER-006-1) and 83.37% (OPA and RTA). The NERC Board adopted
the proposed standard, definitions, and retirements on August 11, 2016.

18
NERC did not immediately file the proposed PRC-027-1 with the Commission following the Board’s
November 2015 adoption of the standard so as to present to the Commission the retirement of PRC-001-1.1(ii) in its
entirety following the adoption of PER-006-1 and the retirement of the remaining requirements in PRC-001-1.1(ii).

9

IV.

JUSTIFICATION FOR APPROVAL
As discussed below and in Exhibit C, the proposed Reliability Standards, NERC Glossary

definitions and the retirement of PRC-001-1.1(ii) satisfy the Commission’s criteria in Order No.
672 and are just, reasonable, not unduly discriminatory, or preferential, and in the public interest.
As noted above, the purpose of the proposed Reliability Standards and the proposed NERC
Glossary definitions is to: (1) maintain the coordination of Protection Systems installed to detect
and isolate Faults on BES Elements, such that those Protection Systems operate in the intended
sequence during Faults; and (2) require registered entities to provide training to their relevant
personnel on Protection Systems and RAS to help ensure that the BES is reliably operated.
Reliability Standard PRC-001-1.1(ii) currently addresses issues related to the coordination of
Protection Systems. As explained further below, NERC proposes to retire Reliability Standard
PRC-001-1.1(ii) as the requirements therein are being replaced by proposed Reliability Standards
PRC-027-1 and PER-006-1 and the proposed definitions, or are addressed by Reliability Standards
approved by the Commission since the effective date of PRC-001-1.
The following section is organized as follows:
1) A discussion of proposed Reliability Standard PER-006-1, the revisions to the definition
of OPA and RTA, and the manner in which they, along with currently-effective
Reliability Standards PER-003-1 and PER-005-2, replace and improve upon Requirement
R1 of PRC-001-1.1(ii).
2) A discussion of proposed Reliability Standard PRC-027-1, the new NERC Glossary term
Protection System Coordination Study, and the manner in which they replace and
improve upon Requirements R3 and R4 of PRC-001-1.1(ii).
3) A discussion of the manner in which Commission-approved TOP and IRO Reliability
Standards replace and improve upon Requirements R2, R5 and R6 of PRC-001-1.1(ii).
4) An explanation of the manner in which Commission-approved TOP and IRO Reliability
Standards resolve outstanding Commission directives related to PRC-001-1.1(ii).
5) A discussion on the enforceability of the proposed Reliability Standards.

10

A.

PER Reliability Standards and Retirement of Requirement R1 of PRC-0011.1(ii)

Reliability Standard PRC-001-1.1(ii), Requirement R1 provides that “[e]ach Transmission
Operator, Balancing Authority, and Generator Operator shall be familiar with the purpose and
limitations of Protection System schemes applied in its area.” This requirement serves an
important reliability objective as Protection Systems and RAS are an integral part of reliable BES
operation and must be applied and operated reliably. 19 As noted above, Protection Systems help
maintain reliability by detecting and isolating faulted equipment, thereby limiting the severity and
spread of system disturbances, and preventing damage to protected BES Elements. Further, the
functions, settings, and limitations of Protection Systems schemes are critical in establishing SOLs
and IROLs. In addition, RAS help maintain BES stability, voltages, and power flows, and limit
the impact of Cascading or extreme events.
When Generator Operator, Transmission Operator, and Balancing Authority personnel
understand the purpose and functions of Protection System schemes applied in their area, they can
operate the BES in a more reliable manner, as follows:
•

When Generator Operator personnel understand the purpose and limitations of Protection
System schemes, the Generator Operator better understands how those schemes affect the
output of their generation facilities and, in turn, are better equipped to operate their
generation facilities to maintain reliability.

•

When Transmission Operator personnel are familiar with the purpose and limitations of
Protection System schemes in their area, the Transmission Operator has a better
understanding of the manner in which their system operates and, in turn, can more
effectively operate their system within SOLs and IROLs, and identify when the reliability
of the system is threatened or reduced.

•

When Balancing Authority personnel are familiar with the purpose and limitations of
Protection System schemes in their area, the Balancing Authority has a better
understanding of the manner in which these schemes affect the maintenance of generation,

19
The phrase “Protection System schemes” in PRC-001-1.1(ii), Requirement R1 maps to both the NERC
Glossary terms “Protection Systems” and “Remedial Action Schemes.” As RAS are essentially schemes comprised
of Protection Systems, the phrase “Protection System schemes” would include RAS.

11

load and interchange balance and, in turn, can ensure that Protection Schemes are enabled
when needed for reliability.
The language of PRC-001-1.1(ii), Requirement R1, however, has created some
uncertainties. First, because the requirement does not specify the type of Generator Operator,
Transmission Operator, or Balancing Authority personnel that must be familiar with the purpose
and limitations of Protection System schemes, it is unclear to many industry stakeholders which
personnel must have the requisite familiarity for the functional entity to satisfy the requirement.
There is also uncertainty as to the steps an applicable entity must take to demonstrate that it has
the requisite familiarity. For example, applicable entities are uncertain whether the standard
requires them to conduct formal training of certain personnel whose job functions relate to or could
be affected by Protection System schemes, or whether it is sufficient for the entity to have reference
documents discussing the purpose and limitations of Protection System schemes that personnel
may review when they deem necessary.
Due to the importance of Protection Systems to the reliable operation of the BPS, the
Reliability Standards related to these systems should set clear obligations. To that end, NERC
proposes to replace PRC-001-1.1(ii), Requirement R1 with new and existing formal training
requirements in the PER group of Reliability Standards. Focusing on formal training requirements
will help ensure that the necessary personnel are familiar with and understand the purpose and
limitations of Protection System schemes while providing more precise and auditable
requirements. The following sections discuss the manner in which proposed Reliability Standard
PER-006-1 and currently-effective Reliability Standards PER-003-1 and PER-005-2, collectively
provide for formal training requirements for Generator Operators, Transmission Operators, and
Balancing Authorities on Protection Systems and RAS, consistent with the objective of PRC-0011.1(ii), Requirement R1. Further, as discussed below, the revisions to the definitions of OPA and
12

RTA will also ensure that Transmission Operators, along with Reliability Coordinators, are
familiar with and consider the functions and limitation of Protection Systems and RAS as they
carry out their reliability functions.
1. Generator Operators
Currently-effective Reliability Standard PER-005-2, Requirement R6 and proposed
Reliability Standard PER-006-1 address Generator Operator familiarity with the purpose and
limitations of Protection System schemes. As discussed below, these standards provide more
precise, auditable and enforceable requirements to meet the objective of Requirement R1 of PRC001-1.1(ii) by: (1) focusing on formal training requirements; (2) clearly identifying the Generator
Operator personnel that must receive training; (3) referencing both Protection Systems and RAS,
instead of the undefined term “Protection System scheme;” and (4) clarifying the subject matter of
the training on Protection Systems and RAS.
Reliability Standard PER-005-2, Requirement R6 and proposed PER-006-1 improve upon
existing Reliability Standard PRC-001-1.1(ii) by establishing formal requirements for all relevant
Generator Operator personnel on Protection Systems and RAS. Reliability Standard PER-005-2,
Requirement R6, which became effective on July 1, 2016, provides that Generator Operators must
use a systematic approach to develop and implement training for dispatch personnel at centrally
located dispatch centers “on how their job function(s) impact the reliable operations of the BES
during normal and emergency operations.” 20 PER-005-2, Requirement R6 thus creates an
20
The specific Generator Operator personnel that must be trained using a systematic approach under PER005-2 are “[d]ispatch personnel at a centrally located dispatch center who receive direction from the Generator
Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and may
develop specific dispatch instructions for plant operators under their control.” PER-005-2, Requirement R6 was
specifically developed to respond to a specific FERC directive from Order Nos. 693 and 742 to include training
requirements for centrally-located dispatch personnel. Mandatory Reliability Standards for the Bulk-Power System,
72 Fed. Reg. 16416 (2007), FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053
(2007); System Personnel Training Reliability Standards, Order No. 742, 133 FERC ¶ 61,159 75 Fed. Reg. 72664
(2010).

13

affirmative obligation for Generator Operators, using a systematic approach, to (1) identify the
manner in which the job functions of centrally-located dispatch personnel could impact the reliable
operations of the BES, including among other things, as it relates to the functionality of Protection
System schemes, and (2) develop and implement the necessary training to help ensure that the
dispatchers carry out their job functions in a manner that will not adversely impact BES reliability.
If the dispatch personnel’s job function can impact the reliable operation of Protection Systems
and RAS, then the Generator Operator must train the dispatcher on the manner in which its job
functions could impact Protection Systems and RAS. 21
Recognizing that PER-005-2, Requirement R6 is limited to centrally-located dispatch
personnel, the Project 2007-6.2 standard drafting team (“SDT”) developed proposed Reliability
Standard PER-006-1 to cover other Generator Operator personnel whose job functions necessitate
that they be trained on the purpose and limitations of Protection System schemes. Specifically,
“[p]lant personnel who are responsible for the Real‐time control of a generator and receive
Operating Instruction(s) from the Generator Operator’s Reliability Coordinator, Balancing
Authority, Transmission Operator, or centrally located dispatch center.” 22 It is appropriate to train
plant personnel with Real-time control of a generator as it is those individuals whose actions could
impact the reliable operation of the BES and who, in turn, need to understand the functionality of
Protection Systems and RAS and how they could affect the generation facility at which they have
control. 23

21

For instance, the centrally located dispatchers may need to understand the circumstances for which the
functionality or limitations of a Protection System or RAS may create a risk under specific dispatch instructions.

22

Proposed Reliability Standard PER-006-1 Applicability section 4.1.1.1.

23
Plant personnel that do not have Real-time control include, for example, fuel handlers, electricians,
machinists, or maintenance staff.

14

For these personnel, proposed PER-006-1 establishes a formal training requirement that
that states:
Each Generator Operator shall provide training to personnel identified in
Applicability section 4.1.1.1 on the operational functionality of Protection Systems
and Remedial Action Schemes (RAS) that affect the output of the generating
Facility(ies) it operates.
The proposed standard represents an improvement over existing PRC-001-1.1(ii) in several
key respects. First, proposed PER-006-1 specifically references Protection Systems and RAS to
avoid confusion as to the scope of the phrase “Protection System schemes,” which is used in PRC001-1.1(ii). As noted above, as RAS are essentially schemes comprised of Protection Systems,
the phrase “Protection System scheme” maps to both the NERC Glossary terms “Protection
System” and “RAS.” To avoid any confusion as to whether RAS must be the subject of training
under Requirement R1 of proposed PER-006-1, the SDT specifically referenced Protection
Systems and RAS.
Proposed PER-006-1 also uses the phrase “operational functionality” instead of the phrase
“purpose and limitations” used in PRC-001-1(ii) to more clearly identify the objective of the
training. The phrase “operational functionality” focuses the required training on (1) the manner in
which Protection Systems operate and prevent damage to BES Elements, and (2) the manner in
which a RAS detects pre‐determined BES conditions and automatically takes corrective actions.
These are the key elements for which Generator Operator personnel need be aware to reliably
operate their facilities. Training on the operational functionality of Protection Systems and RAS
may include, among other things, the following topics: the purpose of protective relays and RAS;
zones of protection; protection communication systems (e.g., line current differential, direct
transfer trip, etc.); voltage and current inputs; station dc supply associated with protective

15

functions; resulting actions, such as tripping/closing of breakers; tripping of a generator step‐up
transformer, or generator ramping/tripping control functions.
Additionally, PER-006-1 uses the phrase “that affect the output of the generating
Facility(ies) it operates” in lieu of the phrase “applied in its area” from PRC-001-1.1(ii). First,
NERC Reliability Standards do not use the concept of a Generator Operator area as is done for
Balancing Authorities and Transmission Operators. Second, in contrast to Balancing Authorities
and Transmission Operators, Generator Operators are not required to monitor or study BES
reliability in their area and do not have the same wide area view of BES reliability to know the
precise manner in which their facility could affect the BES in Real-time. The focus of Generator
Operator reliability functions under NERC’s Reliability Standards is thus on the reliable operation
of their generation facilities. Consistent with that reliability objective, the phrase “that affect the
output of the generating Facility(ies) it operates” properly tailors the scope of training required for
Generator Operators. Under proposed Reliability Standard PER-006-1, Generator Operators must
identify those Protection Systems and RAS that affect the output of their generation facilities and
train the applicable personnel on the operational functionality of those Protection Systems and
RAS.
The proposed standard does not specify a periodicity for the required training. NERC
expects applicable entities to train their plant operating personnel prior to such personnel
performing any Real-time operations. NERC also expects that Generator Operators update the
training to reflect any changes to the operational functionality of Protection Systems and RAS.
2. Transmission Operators and Balancing Authorities
For Transmission Operators and Balancing Authorities, the reliability goal of Requirement
R1 of PRC-001-1.1(ii) is addressed by the existing certification and training requirements in the

16

PER group of Reliability Standards, specifically PER-003-1 and PER-005-2. As discussed below,
these requirements help ensure that the relevant Transmission Operator and Balancing Authority
personnel have the requisite knowledge of Protection Systems and RAS, among other things, to
effectively carry out their reliability-related tasks. Further, these requirements help ensure that
these personnel receive ongoing training to continue to reinforce the skills and knowledge required
for those tasks. The proposed modifications to the definitions of OPA and RTA further the
objective of PRC-001-1.1(ii), Requirement R1 by requiring that Transmission Operators consider
the functions and limitations of Protection Systems and RAS when performing the OPAs and
RTAs required under TOP Reliability Standards to determine whether there are any actual or
expected SOL exceedances. These requirements are each discussed in turn, below.
i.

PER-003-1 Certification Requirements

Pursuant to Reliability Standard PER-003-1, each Reliability Coordinator, Transmission
Operator, and Balancing Authority must staff its Real-time operating positions performing
reliability-related tasks with System Operators who have demonstrated minimum competency in
the specified areas by obtaining and maintaining the relevant NERC credential. In support of
NERC’s mission to promote the reliability of the North American BPS, NERC administers a
System Operator Certification Program to help ensure that BPS operators have a workforce of
system operators that have the skills and qualifications to reliably operate the BPS. 24 The System
Operator Certification Program provides the framework for operators to obtain initial certification
in one of the following four NERC credentials focusing on a specific functional area of system
operations:

24
NERC maintains the required credentials for over 6,000 system operators working in system control centers
across North America.

17

1) Reliability Operator, which focuses on the skills and knowledge required for Reliability
Coordinator System Operators;
2) Balancing, Interchange, and Transmission Operator, which focusses on the skills and
knowledge required for both Transmission Operator and Balancing Authority System
Operators;
3) Transmission Operator, which focuses on the skills and knowledge required for
Transmission Operator-only System Operators; and
4) Balancing and Interchange Operator, which focuses on the skills and knowledge required
for Balancing Authority-only System Operators.
To obtain any of one these four credentials, an individual must pass the NERC System
Operator Certification Exam applicable to that credential. The system operator certification exams
test specific knowledge of job skills and Reliability Standards, and are designed to prepare
operators to handle the BPS during normal and emergency operations. 25 Once an individual passes
any of these exams, s/he must complete NERC‐approved continuing education program courses
and activities to maintain the certification.
The certification requirements in PER-003-1 help meet the objective of PER-001.1.1(ii),
Requirement R1 by mandating that Transmission Operator and Balancing Authority System
Operators demonstrate that they have the requisite knowledge about Protection Systems and RAS
to maintain reliable operation in their area. Specifically, pursuant to Requirement R2 of PER-0031, each Transmission Operator must staff its Real-time operating positions performing
Transmission Operator reliability-related tasks with System Operators who have demonstrated
minimum competency in certain specified areas, including “protection and control”, by obtaining

25

NERC conducts an extensive job analysis survey of certified operators across the industry to provide the
basis for the exams. The job analysis survey results in an exam content outline for each of the exams. The exam
content outline is the framework used to associate tasks to exam questions. NERC contracts with psychometric
consultants who assist a working group of certified system operators in the development and maintenance of each
exam. The exam working group consists of subject matter experts from all regions of North America.

18

and maintaining valid NERC certification as a (1) Reliability Operator, (2) Balancing, Interchange
and Transmission Operator, or (3) Transmission Operator.
The exams required for these certifications include, among other things, a specific focus
on ensuring that such personnel can demonstrate competency in the area of protection and
control. 26

The protection and control area of the exam includes the following six topics: (1)

analyzing the impact of protection equipment outages on system reliability; (2) ensuring special
protective systems and RAS are enabled when needed for system reliability; (3) maintaining
adequate protective relaying during all phases of system restoration; (4) analyzing relay targets,
fault locaters and fault recorders to determine a proper restoration plan following a system event;
(5) taking action in response to alarms from special protective schemes; and (6) scheduling system
telecommunications, telemetering, protection, and control equipment outages to ensure system
reliability.
Similarly, Requirement R3 provides that each Balancing Authority shall staff its Real-time
operating positions performing Balancing Authority reliability-related tasks with System
Operators who have demonstrated minimum competency in certain areas by obtaining and
maintaining valid NERC certification as a (1) Reliability Operator, (2) Balancing, Interchange and
Transmission Operator, or (3) Balancing and Interchange Operator. While “protection and
control” is not a specific area of competency listed in Requirement R3, each of the exams required
to obtain the requisite certifications include topics related to Protection Systems.
Specifically, the exams for the (1) Reliability Operator certificate and (2) Balancing,
Interchange and Transmission Operator certificate are also used for Reliability Coordinator and

26

See, e.g., NERC’s Transmission Operator Certification Exam Content Outline 2015, available at
http://www.nerc.com/pa/Train/SysOpCert/System%20Operator%20Certification%20DL/Transmission%20Operator
%20Certification%20Exam%20Content%20Outline%202015.pdf.

19

Transmission Operator System Operator certification, respectively, and thus include “protection
and control” as an area of specific focus. The Balancing and Interchange Operator certificate
exam, which is acceptable for Balancing Authority-only System Operators and does not include
“protection and control” as a specified area of focus, nevertheless includes five of the six topics
related to Protection Systems and RAS that are in the other exams. Specifically, the Balancing
and Interchange Operator exam includes, among others, questions related to the following topics:
(1) analyzing the impact of protection equipment outages on system reliability; (2) ensuring special
protective systems and RAS are enabled when needed for system reliability; (3) maintaining
adequate protective relaying during all phases of system restoration; (4) taking action in response
to alarms from special protective schemes; and (5) scheduling system telecommunications,
telemetering, protection, and control equipment outages to ensure system reliability. 27
ii.

PER-005-2 Training Requirements

In addition to the certification requirements of PER-003-1, Reliability Standard PER-0052 includes a number of requirements that collectively satisfy the objective of ensuring that
Transmission Operators and Balancing Authorities are familiar with the purpose and limitations
of Protection System schemes. First, pursuant to Requirement R1, each Transmission Operator
and Balancing Authority must use a systematic approach to develop and implement a training
program for its System Operators that, among other things, includes regular training on Protection
Systems and RAS. Specifically, Requirement R1 requires Transmission Operators and Balancing
Authorities to:
•

Create a list of BES “company-specific Real-time reliability-related tasks based on a
defined and documented methodology” that is updated on an annual basis (Part 1.1).

27

See NERC’s Balancing and Interchange Operator Certification Exam Content Outline 2015, available at
http://www.nerc.com/pa/Train/SysOpCert/System%20Operator%20Certification%20DL/Balancing%20and%20Inte
rchange%20Operator%20Certification%20Exam%20Content%20Outline%202015.pdf.

20

•

Design and develop training materials based on the BES company-specific Real-time
reliability-related task list (Part 1.2).

•

Deliver the training to its System Operators (Part 1.3).

•

Conduct an evaluation each calendar year of its training program to identify any needed
changes to the training program and implement the identified changes (Part 1.4).
As the certification exams described above indicate, the Real-time reliability-related tasks

of Transmission Operator and Balancing Authority System Operators relate to the operation of
Protection Systems and RAS. The training programs required under Requirement R1 must thus
include training on topics related to Protection Systems and RAS. The proposed revisions to the
definitions of OPA and RTA, which, as further discussed below, require Transmission Operators
to consider the functions and limitations of Protection Systems and RAS when performing OPAs
and RTAs, further highlight that addressing issues related to Protection Systems and RAS are part
of a Transmission Operator’s Real-time reliability-related tasks and, in turn, should be included in
the training program under PER-005-2, Requirement R1.
Additionally, Requirement R3 of PER-005-2 provides that Transmission Operators and
Balancing Authorities must verify that its System Operators are capable of performing each of the
company-specific Real-time reliability-related tasks identified under Requirement R1.

This

requirement helps ensure that the System Operator who is engaged in tasks associated with
Protection Systems and RAS are capable of performing those tasks. In verifying that capability,
Transmission Operators and Balancing Authorities must confirm that the System Operator
understands the functions and limitations of the relevant Protection Systems and RAS.
Requirement R4 further reinforces these capabilities by requiring each Transmission
Operator and Balancing Authority that “(1) has operational authority or control over Facilities with
established [IROLs], or (2) has established protection systems or operating guides to mitigate
IROL violations,” to provide its System Operators with emergency operations training using
21

simulation technology such as a simulator, virtual technology, or other technology that replicates
the operational behavior of the BES. Simulation training further enhances System Operator
understanding of the relevant Protection Systems and RAS and the manner in which they impact
BES operations.
Lastly, PER-005-2, Requirement R5 helps ensure that Transmission Operators and
Balancing Authorities provide training to personnel who are not System Operators but have job
functions that impact Real-time reliability-related tasks related to Protection Systems and RAS.
Specifically, Requirement R5 provides that Transmission Operators and Balancing Authorities
must “use a systematic approach to develop and implement training for its identified Operations
Support Personnel on how their job function(s) impact those BES company-specific Real-time
reliability-related tasks identified” pursuant to Requirement R1. 28 As Operations Support
Personnel perform OPAs and RTA in support of outage coordination and establishment of SOLs
and IROLs, the required training should include material fostering an appropriate understanding
of the functions and limitations of Protection Systems and RAS in their area, consistent with the
objectives of PRC-001-1.1(ii), Requirement R1 and the modifications to the definition of OPA and
RTA.
iii.

Revised OPA and RTA Definitions

As discussed further in Exhibit E hereto, NERC also proposes modifications to the
definitions of OPA and RTA to include the functions and limitations of Protection System and
RAS as a required input for OPAs and RTAs. The modifications further the objective of PRC001-1.1(ii), Requirement R1 by requiring entities to consider the functions and limitations of

28

Operations Support Personnel are “individuals who perform current day or next day outage coordination or
assessments, or who determine SOLs, IROLs, or operating nomograms, in direct support of Real-time operations of
the Bulk Electric System.”

22

Protection Systems and RAS when assessing anticipated and potential conditions for next-day
operations time frame (OPAs) and existing and potential operating conditions in Real-time
(RTAs).
Pursuant to Commission-approved Reliability Standard TOP-002-4, Requirements R1 and
R2, Transmission Operators are required to: (1) “have an [OPA] that will allow it to assess whether
its planned operations for the next day within its Transmission Operator Area will exceed any of
its [SOLs];” and (2) “have an Operating Plan(s) for next-day operations to address potential [SOL]
exceedances identified as a result of its [OPA].”
The Commission approved definition of OPA is:
An evaluation of projected system conditions to assess anticipated (preContingency) and potential (post-Contingency) conditions for next-day operations.
The evaluation shall reflect applicable inputs including, but not limited to, load
forecasts; generation output levels; Interchange; known Protection System and
Special Protection System status or degradation; Transmission outages; generator
outages; Facility Ratings; and identified phase angle and equipment limitations.
(Operational Planning Analysis may be provided through internal systems or
through third-party services.)
To ensure that the functions and limitation of Protection Systems and RAS are inputs into
the OPA, NERC is proposing to modify the definition as follows:
An evaluation of projected system conditions to assess anticipated (preContingency) and potential (post-Contingency) conditions for next-day operations.
The evaluation shall reflect applicable inputs including, but not limited to:, load
forecasts; generation output levels; Interchange; known Protection System and
Special Protection System Remedial Action Scheme status or degradation,
functions, and limitations; Transmission outages; generator outages; Facility
Ratings; and identified phase angle and equipment limitations. (Operational
Planning Analysis may be provided through internal systems or through third-party
services.) 29

29

NERC proposes to replace the term “Special Protection System” with “Remedial Action Scheme” to reflect
the transition across NERC standards to using RAS. See N. Am. Elec. Reliability Corp., Docket No. RD16-5-000
(Jun. 23, 2016) (unpublished letter order).

23

Similarly, under Commission-approved Reliability Standard TOP-001-3, Requirements
R13 and R14, each Transmission Operator is required to: (1) perform a RTA at least once every
30 minutes; and (2) initiate its Operating Plan to mitigate a SOL exceedance identified as part of
its Real-time monitoring or RTA. The current definition of RTA is:
An evaluation of system conditions using Real-time data to assess existing (preContingency) and potential (post-Contingency) operating conditions. The
assessment shall reflect applicable inputs including, but not limited to: load,
generation output levels, known Protection System and Special Protection System
status or degradation; Transmission outages, generator outages, Interchange;
Facility Ratings, and identified phase angle and equipment limitations. (Real-time
Assessment may be provided through internal systems or through third-party
services.)
As with the modifications to the OPA definition, to ensure that the functions and limitation
of Protection Systems and RAS are inputs into the RTA, NERC is proposing to modify the
definition as follows:
An evaluation of system conditions using Real-time data to assess existing (preContingency) and potential (post-Contingency) operating conditions. The
assessment shall reflect applicable inputs including, but not limited to: load;
generation output levels; known Protection System and Special Protection System
Remedial Action Scheme status or degradation, functions, and limitations;
Transmission outages; generator outages; Interchange; Facility Ratings; and
identified phase angle and equipment limitations. (Real-time Assessment may be
provided through internal systems or through third-party services.)
3. Reliability Coordinators
Although PRC-001.1.1(ii), Requirement R1 does not apply to Reliability Coordinators, it
is also important for Reliability Coordinator personnel to understand the functions and limitations
of Protection Systems and RAS and consider that information when conducting OPAs and RTAs.
The Reliability Coordinator has a central role in maintaining BES reliability, particularly with
respect to helping to ensure that the BES is operated within SOLs and IROLs. As such, an
understanding of Protection Systems and RAS is vital to the functional obligations of a Reliability
Coordinator.
24

Accordingly, as is the case for Transmission Operators and Balancing Authorities, NERC’s
currently-approved Reliability Standards require the following to help ensure that Reliability
Coordinator personnel have the requisite understanding of Protection Systems and RAS:
•

Reliability Coordinators must staff their Real-time operating positions performing
Reliability Coordinator reliability-related tasks with System Operators who have
demonstrated competency in the area of “protection and control,” among others, through
the NERC System Operator Certification Program (PER-003-1, Requirement R1).

•

Reliability Coordinators must train their System Operators, using a systematic approach,
on their Real-time reliability related tasks, which may include tasks related to Protection
Systems and RAS (PER-005-2, Requirement R1).

•

Reliability Coordinators must verify that their System Operators are capable of performing
each of the company-specific Real-time reliability-related tasks identified under PER-0052, Requirement R1 (PER-005-2, Requirement R3).

•

Reliability Coordinators that have (1) operational authority or control over Facilities with
established IROLs, or (2) established protection systems or operating guides to mitigate
IROL violations, must provide their System Operators emergency operations training using
simulation technology such as a simulator, virtual technology, or other technology that
replicates the operational behavior of the BES (PER-005-2, Requirement R4).

•

Reliability Coordinators must provide training, using a systematic approach, to Operations
Support Personnel on how their job function(s), including those related to Protection
Systems and RAS, impact those BES company-specific Real-time reliability-related tasks
identified pursuant to PER-005-2, Requirement R1.
In addition to these Commission-approved certification and training requirements, the

modifications to the definitions of OPA and RTA require Reliability Coordinators to consider the
functions and limitations of Protection Systems and RAS when conducting OPAs and RTAs to
assess whether there are any actual or expected SOL or IROL exceedances, pursuant to Reliability
Standard IRO-008-2, Requirements R1, R4 and R5. As the modifications to the definitions of
OPA and RTA also apply to the Reliability Coordinator, they serve to enhance the manner in which
the reliability objective of PRC-001-1.1(ii), Requirement R1 is met in NERC’s Reliability
Standards.

25

B.

PRC-027-1 and Retirement of Requirements R3 and R4 of PRC-001-1.1(ii)

Proposed Reliability Standard PRC-027-1 is designed to improve upon and replace
Requirements R3 and R4 of PRC-001-1.1(ii) in addressing the coordination of Protection Systems
installed to detect and isolate Faults on the BES, such that those Protection Systems operate in
their intended sequence during Faults. As noted above, coordinated Protection Systems enhance
reliability by reducing the risk of BES instability or Cascading, and leaving the remainder of the
BES operational and more capable of withstanding the next Contingency. Specifically, when
Faults occur, properly coordinated Protection Systems minimize the number of BES Elements that
are removed from service and protect equipment from damage.
Proposed Reliability Standard PRC-027-1 provides a clear set of Requirements that
obligate entities to (1) implement a process for establishing and coordinating new or revised
Protection System settings, and (2) periodically study Protection System settings that could be
affected by incremental changes in Fault current to ensure the Protection Systems continue to
operate in their intended sequence. Specifically, proposed PRC-027-1 consists of the following
three requirements, each of which is discussed in greater detail below:
•

Requirement R1 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider establish a process for developing new and revised Protection System
settings for BES Elements to operate in the intended sequence during Faults. The process
must include provisions for coordinating those settings with owners of electrically joined
facilities.

•

Requirement R2 mandates that, for each BES Element with a Protection System that could
be affected by changes in Fault current, applicable entities must, every six years, determine
whether the Protection System settings continue to be appropriate by: (1) performing a
Protection System Coordination Study; (2) first evaluating whether there were any changes
in Fault current that could affect the coordination of Protection System and, if so,
performing a Protection System Coordination Study; or (3) a combination of the above two
options. The proposed definition for the term Protection System Coordination Study is
“[a]n analysis to determine whether Protection Systems operate in the intended sequence
during Faults.”

26

•

Requirement R3 requires applicable entities to implement the process established
according to Requirement R1 for developing new or revised Protection System settings.

Collectively, these Requirements help ensure that Protection Systems are installed in a coordinated
manner and operate in the intended sequence to isolate Faults on the BES.
Proposed Reliability PRC-027-1 improves upon Requirements R3 and R4 of PRC-0011.1(ii) by:
•

Assigning the responsibility for performing coordination responsibilities to the owners of
the Protection Systems whose functional obligations include setting, coordinating, and
maintaining Protection Systems.

•

Clarifying that proposed PRC-027-1 pertains to the coordination of Protection Systems
associated with Fault clearing.

•

Clarifying that the scope of the proposed standard applies to any Protection System
installed to detect and isolate Faults on BES Elements, regardless of location (i.e., internal
lines as well as tie-lines).

•

Adding a Requirement that applicable entities establish and use a process to develop
settings for their BES Protection Systems that must contain certain specified attributes.

•

Adding a Requirement that applicable entities periodically perform Protection System
Coordination Studies and/or review Fault current values for existing Protection Systems
applied on BES Elements that are identified as being affected by changes in Fault current
to determine whether the settings continue to be appropriate.
The following is a discussion of the applicability of the proposed standard and an analysis

of each Requirement.
1. Applicability
Proposed Reliability Standard PRC-027-1 is applicable to Transmission Owners,
Generator Owners, and Distribution Providers as these are the entities that own and install
Protection Systems for the purpose of detecting Faults in the BES and have the functional
obligations to maintain those Protection Systems. Transmission Owners own the largest number
of Protection Systems installed for the purpose of detecting Faults on the BES. Generator Owners
also have Protection Systems installed for the purpose of detecting Faults on the BES and it is
27

important that those Protection Systems are coordinated with Protection Systems owned by
Transmission Owners to ensure that generation Facilities do not become disconnected from the
BES unnecessarily. Functions such as impedance reaches, overcurrent pickups, and time delays
need to be evaluated for coordination. Lastly, Distribution Providers may provide an electrical
interconnection and path to the BES for generators that will contribute current to Faults that occur
on the BES. If the Distribution Provider owns Protection Systems that operate for those Faults, it
is important that those Protection Systems are coordinated with other Protection Systems that can
be impacted by the current contribution to the Fault of the Distribution Provider.
As the owners of the Protection Systems, these entities should have the obligation to
implement a coordinated process for developing new and revised Protection System settings and
reviewing those setting on a periodic basis. Under the NERC Functional Model, the reliability
tasks related to Transmission, Distribution, and Generation Ownership include design and
maintenance of Protection Systems. 30 These functions include developing Protection System
settings, evaluating Protection System operations, and identifying Protection System
Misoperations. As part of designing the Protection Systems, these entities must coordinate with
their neighbors to ensure the Protection System operates in the intended sequence during Faults.
In contrast, Transmission Operators and Generator Operators are only concerned with Protection
Systems after they are placed in service.

30

The Functional Model provides (at p. 44) that Transmission Ownership includes the following task:
“Design and authorize maintenance of transmission protective relaying systems and Special Protection Systems.”
For Distribution, the Functional Model (at p. 46) lists the following as a task: “Design and maintain protective
relaying systems, under-frequency load shedding systems, under-voltage load shedding systems, and Special
Protection Systems that interface with the transmission system.” Lastly, the Functional Model (at p. 50), includes
the following task for Generation Ownership: “Design and authorize maintenance of generation plant protective
relaying systems, protective relaying systems on the transmission lines connecting the generation plant to the
transmission system, and Special Protection Systems.” The Functional Model is available at:
http://www.nerc.com/pa/Stand/Functional%20Model%20Archive%201/Functional_Model_V5_Final_2009Dec1.pdf

28

In addition to clarifying the functional entities responsible for performing coordination
responsibilities, proposed Reliability Standard PRC-027-1 also clarifies that the standard only
applies to coordination of Protection Systems associated with Fault clearing. Aspects of protection
coordination other than Fault coordination are addressed by other Reliability Standards.
Specifically, other protection issues, such as over/under frequency, over/under voltage,
coordination of generating unit or plant voltage regulating controls, and relay loadability are
addressed by the following Reliability Standards:
•

Underfrequency Load shedding programs are addressed in PRC‐006‐2.

•

Undervoltage Load shedding programs are addressed in PRC‐010‐2.

•

Generator performance during declined frequency and voltage excursions is addressed in
PRC‐024‐2.

•

Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and
Protection is addressed in PRC‐019‐2.

•

Transmission relay loadability is addressed in PRC‐023‐3.

•

Generator relay loadability is addressed in PRC‐025‐1.

•

Protective relay response during stable power swings is addressed in PRC‐026‐1.

•

Protection System Misoperations (including those caused by coordination issues) are
addressed in PRC‐004‐5i.
Additionally, whereas Requirement R4 of PRC-001-1.1(ii) is limited to the coordination

of Protection Systems on “major transmission lines,” the Requirements of PRC-027-1 apply to any
Protection System installed to detect and isolate Faults on BES Elements, regardless of location,
size, or whether they are tie-lines or internal lines. Eliminating the phrase “major transmission
lines” also avoids the ambiguities involved in determining which lines are “major.”
2. Requirement R1
Requirement R1 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider establish a process for developing new and revised Protection System
settings for BES Elements, such that those Protection Systems operate in the intended sequence
29

during Faults (i.e., are properly coordinated). The process must include provisions designed to
ensure that the settings are accurate and coordinated with owners of electrically joined facilities.
Specifically, Requirement R1 provides:
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall
establish a process for developing new and revised Protection System settings for
BES Elements, such that the Protection Systems operate in the intended sequence
during Faults. The process shall include:
1.1.

A review and update of short-circuit model data for the BES Elements
under study.

1.2.

A review of the developed Protection System settings.

1.3.

For Protection System settings applied on BES Elements that electrically
join Facilities owned by separate functional entities (Transmission
Owners, Generator Owners, and Distribution Providers), provisions to:
1.3.1. Provide the proposed Protection System settings to the owner(s) of
the electrically joined Facilities.
1.3.2. Respond to any owner(s) that provided its proposed Protection
System settings pursuant to Requirement R1, Part 1.3.1 by
identifying any coordination issue(s) or affirming that no
coordination issue(s) were identified.
1.3.3. Verify that identified coordination issue(s) associated with the
proposed Protection System settings for the associated BES
Elements are addressed prior to implementation.
1.3.4. Communicate with the other owner(s) of the electrically joined
Facilities regarding revised Protection System settings resulting
from unforeseen circumstances that arise during implementation or
commissioning, Misoperation investigations, maintenance
activities, or emergency replacements required as a result of
Protection System component failure.

This Requirement applies to changes to Protection System settings for any BES Element.
Although the coordination of some Protection Systems may seem unnecessary, such as for a line
that is protected solely by dual current differential relays, backup Protection Systems that are
enabled to operate based on current or apparent impedance with some definite or inverse time

30

delay must be coordinated with other Protection Systems of the BES Element such that tripping
does not unnecessarily occur for Faults outside of the differential zone.
The following is a discussion of each Part of Requirement R1:
Part 1.1 helps ensure that applicable entities develop any new or revised Protection System
settings using accurate and updated data by requiring them to review and update short-circuit
model data for the BES Element(s) under study. 31 A short-circuit study is an analysis of an
electrical network that determines the magnitude of the currents flowing in the network during an
electrical Fault. These studies form the basis for the development of Protection System settings
as they provide the necessary Fault currents used by protection engineers to develop Protection
System settings. Requiring a review and, if necessary, an update of short-circuit model data is
thus necessary to ensure that the information that forms the basis of the development of Protection
System settings is accurate and reflects the physical power system. The review of short-circle
model data would include a review of:
•

applicable BES line, transformer, and generator impedances and Fault currents;

•

the network model to confirm the network in the study accurately reflects the configuration
of the actual System, or how the System will be configured when the proposed relay
settings are installed; and

•

where applicable, interconnected Transmission Owner, Generator Owner, and Distribution
Provider information.
Part 1.2 further supports the development of accurate Protection System settings by

requiring applicable entities to institute a systematic process for verifying that the Protection
System settings are correct (i.e., that they meet applicable technical criteria, as defined by the
entity). A review of the Protection System settings prior to implementation reduces the possibility

31
Although Generator Owners and Distribution Providers may not have or maintain short-circuit models,
NERC expects these entities to obtain the short-circuit model data from their Transmission Planners, Planning
Coordinators, or Transmission Owners.

31

of introducing human error. Examples of reviews include peer reviews, automated checking
programs, and other entity-developed review procedures designed to verify the accuracy of the
settings.
Part 1.3 addresses the coordination of Protection System settings between neighboring
entities for BES Elements that electrically join Facilities owned by separate functional entities.32
Communication among neighboring entities is essential for identifying and resolving coordination
issues prior to implementation of any new or revised Protection System settings. Part 1.3 creates
the following obligations:
•

Under Part 1.3.1, applicable entities proposing to change any Protection System setting for
BES Elements that electrically join facilities owned by separate functional entities must
include in their process provisions for providing proposed Protection System settings to
their neighboring entities so as to allow those entities an opportunity to review those
settings and determine whether there are any coordination issues.

•

Under Part 1.3.2, applicable entities must include in their process provisions for responding
to neighboring entities that provided them proposed Protection System setting under Part
1.3.1 by identifying any coordination issues or affirming that no such issues are present.
These provisions ensure that the proposed settings are reviewed and that the initiating entity
receives a response indicating whether there are any coordination issues to address prior to
implementation.

•

Under Part 1.3.3, applicable entities must include provisions in their process for verifying
that any identified coordination issues are resolved with the neighboring entity prior to
implementation, thereby minimizing any potential impact to BES reliability. 33

32
The exclusion in PRC-001-1.1(ii), Requirement R3, R3.1 for dispersed power producing resources applies
only to interconnections between different functional entities. As such, the exclusion only maps to Requirement R1,
Part 1.3 in PRC-027-1. Due to the design of dispersed generation sites, the Protection Systems applied on the
individual dispersed generation resources are not electrically joined Facilities owned by separate functional entities
as specified in Requirement R1, Part 1.3 nor are they connected by BES Elements. Therefore Requirement R1, Part
1.3 does not apply to the Protection Systems applied on the individual dispersed generation resources. Requirement
R1, Part 1.3 applies only to the Protection Systems applied on the BES Elements that electrically join Facilities
owned by separate functional entities.
33

There could be instances where coordination issues are identified and the entities agree not to mitigate all
of the issues based on engineering judgment. Further, coordination issues identified during a project may not be
immediately resolved if the resolution involves additional system modifications not identified in the initial project
scope. There could also be situations where protection philosophies differ between entities, but the entities can
agree that these differences do not create coordination issues.

32

•

Under Part 1.3.4, applicable entities must have provisions for communicating with
neighboring entities regarding revised Protection System settings resulting from
unforeseen circumstances that arise during implementation or commissioning,
Misoperation investigations, maintenance activities, or emergency replacements required
as a result of Protection System component failure. This Part recognizes that there may be
instances under which changes to Protection Systems need to be made without the
opportunity to coordinate with neighboring entities in the timeframe contemplated under
Parts 1.3.1 through 1.3.3. Nevertheless, those changes need to be coordinated with other
entities to address any issues going forward.
3. Requirement R2
The reliability objective of Requirement R2 is to mitigate risks associated with the impact

of changes in Fault current on Protection Systems installed to detect and isolate Faults on the BES.
Over time, the accumulation of incremental changes in Fault current could affect the coordination
of Protection Systems (i.e., the performance of the Protection System during Faults). Entities
should thus be required to determine whether there were any changes in Fault current that affected
the coordination of Protection Systems and, if so, adjust the settings as necessary to ensure the
Protection System continues to operate in the intended sequence during Faults.
To that end, Requirement R2 mandates that, for BES Elements with Protection Systems
that could be affected by changes in Fault current, applicable entities must, every six years,
determine whether the Protection System settings continue to be appropriate by either: (1)
performing a Protection System Coordination Study for each applicable BES Element to determine
whether the Protection Systems continue to operate in the intended sequence during Faults; or (2)
first evaluating whether there were any changes in Fault current at each BES Element that could
affect the coordination of Protection Systems and, if so, performing a Protection System
Coordination Study for that BES Element; or (3) using a combination of the above options to
conduct a review at each applicable BES Element. Specifically, Requirement R2 provides as
follows:

33

R2.

Each Transmission Owner, Generator Owner, and Distribution Provider shall, for
each BES Element with Protection System functions identified in Attachment A:
•

Option 1: Perform a Protection System Coordination Study in a time interval
not to exceed six-calendar years; or

•

Option 2: Compare present Fault current values to an established Fault current
baseline and perform a Protection System Coordination Study when the
comparison identifies a 15 percent or greater deviation in Fault current values
(either three phase or phase to ground) at a bus to which the BES Element is
connected, all in a time interval not to exceed six-calendar years; or

•

Option 3: Use a combination of the above.

The components of Requirement R2 are discussed further below.
i.

BES Element with Protection System Functions Identified in Attachment A

As noted above, the purpose of Requirement R2 is to periodically review Protection
Systems that could be affected by changes in Fault current to determine whether the settings
continue to be appropriate. Attachment 1 lists those Protection System functions that use current
in their measurement to initiate tripping of circuit breakers and, as a result, changes in the
magnitude of available Fault current could impact the coordination of these functions. Attachment
A provides:
The following Protection System functions are applicable to Requirement R2 if: (1)
available Fault current levels are used to develop the settings for those Protection
System functions; and (2) those Protection System functions require coordination
with other Protection Systems.
21 – Distance if:
•

infeed is used in determining reach (phase and ground distance), or

•

zero-sequence mutual coupling is used in determining reach (ground
distance).

50 – Instantaneous overcurrent
51 – AC inverse time overcurrent

34

67 – AC directional overcurrent if used in a non-communication-aided protection
scheme
The numerical identifiers in Attachment A represent general device functions according to
ANSI/IEEE Standard C37.2 Standard for Electrical Power System Device Function Numbers,
Acronyms, and Contact Designations. Examples of functions not included in Attachment A are
differential relays and Fault detectors as they do not meet the above criteria. 34 Under Requirement
R2, if an applicable entity has any BES Elements with the Protection System functions listed in
Attachment A, the entity must perform a review of the Protection Systems for that BES Element
every six calendar years to determine whether Fault currents have affected the coordination of the
Protection System and the settings need to be changed. Requirement R2, however, provides
entities flexibility in the manner in which it conducts its review of those Protection Systems by
providing three options, as discussed below.
ii.

Option 1 – Performing Protection System Coordination Studies

To satisfy its obligation under Requirement R2, an applicable entity may choose to perform
a full Protection System Coordination Study every six calendar years for each of its applicable
BES Elements. The proposed definition for the new NERC Glossary term Protection System
Coordination Study is “[a]n analysis to determine whether Protection Systems operate in the
intended sequence during Faults.” If the results of the Protection System Coordination Study
reveal that the Protection System requires revised settings to operate in its intended sequence
during faults, the applicable entity would then initiate its process established pursuant to
Requirement R1 to change the settings for those Protection Systems in accordance with the
Protection System Coordination Study.

34

For additional information regarding the Protection System functions listed in Attachment A, see the
Supplemental Material section of the proposed standard.

35

In performing a Protection System Coordination Study, applicable entities would evaluate
current pickup levels, timing characteristics, impedance characteristics, and fault detector levels
of relays to seek the best coordination possible of Protection Systems providing primary and
backup protection of BPS Elements.
iii.

Option 2 – Comparison of Fault Current Values

Under Option 2, instead of immediately conducting Protection System Coordination
Studies for each of its BES Elements with a Protection System function listed in Attachment A, an
entity may first choose to compare present Fault current values at each of those BES Element to
an established Fault current baseline to determine whether a Protection System Coordination Study
is in fact necessary. This option provides entities the flexibility to determine whether there were
any changes in Fault current at the BES Element that could affect Protection System coordination
prior to expending its resources to perform a full Protection System Coordination Study.
Requirement R2 establishes a Fault current deviation of 15% or greater from a baseline
established from the most recent Protection System Coordination Study as the threshold for
determining whether a Protection System Coordination Study is necessary. 35 Specifically, if the
Fault current comparison for a BES Element indicates a deviation of less than 15% from the
established baseline, the applicable entity is not required to conduct a full Protection System
Coordination Study for that BES Element. If, however, the Fault current comparison indicates a
15% percent or greater deviation on a BES Element, the applicable entity is then required to
conduct a full Protection System Coordination Study for that BES Element to determine whether

35

As discussed below, entities seeking to use Option 2 for the initial performance of this Requirement must
establish a baseline by the effective date of the standard based on short-circuit studies.

36

the Protection Systems for that BES Element continue to operate in the intended sequence during
Faults.
NERC proposes a 15% deviation threshold for determining whether a Protection System
Coordination Study is required under Option 2 based on generally‐accepted margins for setting
Protection Systems in which incremental Fault current changes would not interfere with
coordination. Accepted engineering practices require entities to consider proper margins while
setting relays. Those margins are based on measurement errors, possible errors in fault studies, or
unknown system configuration changes that can occur during system disturbances or short term
operating conditions. Margins are used to help ensure that the Protection Systems operate as
designed during any Fault condition and that relatively small (up to 15%) changes in Fault current
do not interfere with that coordination. The 15% maximum deviation provides an entity with
latitude, however, to choose a Fault current deviation threshold that is less than 15% to better
match its protection philosophy, or other business considerations without creating undue risk to
reliability.
If there is a Fault current deviation of 15% or greater and the results of the subsequent
Protection System Coordination Study reveal that a Protection System requires revised settings to
operate in its intended sequence during faults, the applicable entity would then initiate its process
established pursuant to Requirement R1 to change the settings for those Protection Systems in
accordance with the Protection System Coordination Study. As with Option 1, the time interval
for conducting the Fault current comparison and any subsequent Protection System Coordination
Study is six calendar years.
The Fault current values used in the comparison, whether three‐phase or phase‐to‐ground
Fault currents, should be determined with all generation in service and all transmission BES

37

Elements in their normal operating state. Further, the Fault current baseline values used as a point
of reference for the Fault current comparisons can be obtained from the short-circuit studies
performed by the Transmission Planners, Planning Coordinators, or Transmission Owners. As
described in the footnote 1 of the proposed standards, Fault current baselines may be established
for BES generating resources at the generator, the BES aggregation point for dispersed power
producing resources, or at the common point of connection at 100 kV or above.
With respect to the timing for establishing the Fault current baselines, footnote 1 in the
proposed standard provides that an entity that elects to use Option 2 for its initial performance of
this Requirement must establish its baseline by the effective date of the standard and update it each
time it performs a Protection System Coordination Study. If an initial baseline was not established
by the effective date of this Reliability Standard because the applicable entity chose Option 1 or
installed a new BES Element, the entity may establish the baseline upon performing a Protection
System Coordination Study. The baseline values at each bus to which a BES Element is connected
are updated whenever a new Protection System Coordination Study is performed for the subject
Protection System.
The following is a hypothetical example of how Option 2 would work in practice for a
single BES Element: By the effective date of PRC-027-1, Entity X established an initial Fault
current baseline of 10,000 amps at the bus to which the BES Element under study is connected.
Consistent with Option 2, within six years of the effective date, Entity X performed a short-circuit
review to determine the present Fault current value at the bus. The short-circuit review indicated
that the Fault current increased to 11,250 amps, a 12.5% deviation. As the deviation was less than
15%, no Protection System Coordination Study was required for that BES Element. As such, no

38

further action was required and Entity X satisfied its obligations under Requirement R2 for that
first six-year interval.
As required by Requirement R2, six years later Entity X performed another short-circuit
review to determine the present Fault current value at the bus. The baseline value for this Fault
current comparison remains at 10,000 amps because Entity X did not perform a Protection System
Coordination Study as a result of the initial comparison and the baseline was not reset. The results
of this second Fault current comparison indicated that the Fault current increased to 11,500 (a 15%
deviation). To comply with Requirement R2, Entity X must now perform a Protection System
Coordination Study, also to be completed within that six-year interval, and a new baseline of
11,500 amps would be established. If the Protection System Coordination Study indicates a need
to modify the Protection System settings to ensure that the Protection System operates in the
intended sequence, Entity X would use its process developed under Requirement R1 to effectuate
those changes. If the Protection System Coordination Study does not indicate that setting changes
are necessary despite the 15% deviation, Entity X is not required to take any further action
(although its Fault current baseline is reset to 11,500 amps for future comparisons). 36
iv.

Option 3 – Use Combination of Options 1 and 2

Option 3 provides entities the flexibility to use Option 1 at some BES Elements and Option
2 at other BES Elements based on the needs of its system. As Protection Systems at certain BES
Elements are more susceptible to Fault current changes than others, applicable entities should have
the latitude to choose between Option 1 and Option 2 for each BES Element. Where a BES
Element is more susceptible to Fault current changes, the applicable entity may choose to bypass

36

Note that if, as a result of the first Fault current comparison, the entity decided to perform a Protection
System Coordination Study even though there was only a 12.5% deviation and the results of the study indicate that
the settings still meet the setting criteria of the entity, then no settings changes are required but the baseline Fault
current would be updated to 11, 250 amps.

39

a Fault comparison (Option 2) and proceed straight to a Protection System Coordination Study
(Option 1). In contrast, for BES Elements less susceptible to Fault current changes, the entity may
choose Option 2 to do a Fault current comparison and potentially avoid the more resource intensive
Protection System Coordination Study. An entity may, for example, choose Option 1 for all of its
Facilities operated above 300 kV, while choosing to use Option 2 for its Facilities operated below
300 kV. No matter which option the entity chooses for each of its BES Elements, the entire cycle
must be completed every six calendar years.
v.

Six-Year Time Interval

NERC proposes a maximum of six-year intervals to perform the review under Requirement
R2 so as to balance the resources required to perform Protection System Coordination Studies and
the potential reliability impacts created by incremental changes of Fault current over time. 37
Performing Protection System Coordination Studies is a resource intensive activity. These studies
require engineers to review Protection Systems at a number of substations to evaluate the
coordination between the Protection Systems. This review includes performing fault simulations,
creating impedance plots with relay characteristics, and time-overcurrent curve reviews where
little or no change may have occurred during the six-year interval. For entities with many BES
Elements with Protection System functions listed in Attachment A, significant time and personnel
must be devoted to conducting Protection Systems Coordination Studies. To require entities to
perform the Protection System Coordination Studies on shorter intervals may be overly
burdensome without any additional reliability benefit.
NERC event analysis data supports the six-year intervals. Specifically, NERC reviewed
its events analysis data from 2012-2015 to determine the number of instances in which Protection

37

Entities may choose to do the review in shorter intervals.

40

System coordination issues led to an event on the BES. 38 During 2012-2015, the number of events
reported through the NERC Event Analysis process that had, as part of the event, more than one
Misoperation due to incorrect settings is as follows:
•

2012 - three events out of a total of 45 Misoperation events (115 total qualified events)

•

2013 - five events out of a total of 34 Misoperation events (140 total qualified events)

•

2014 - four events out of a total of 34 Misoperation events (171 total qualified events)

•

2015 - five events out of a total of 38 Misoperation events (148 total qualified events)
This data shows that Protection System coordination is not a significant issue on the BES

in terms of number of events. From 2012 through 2015, only 11% of Misoperation events (17
events out of 151) and only 2.9% of total events (17 out of 574) involved Protection System
coordination issues. Of the 17 events involving coordination issues, five were inter-company and
12 intra-company. 39 Given this data, the burden of requiring entities perform Protection System
Coordination Studies at a time interval shorter than six years outweighs the reliability benefit of
doing so.
As noted above, Requirement R2 is designed to capture incremental Fault changes that
accumulate over time and could affect the coordination of Protection Systems eventually. Any
changes to BPS Elements that require changes to Protection System settings will be addressed
through the Requirement R1 process and implemented pursuant to Requirement R3. As such,
significant accrued Fault current changes will not be likely without some evaluation due to the
system changes.

Requirement R2 provides assurance that entities do confirm coordination

38

A coordination event was defined as an event that had more than one Protection System Misoperation. An
event resulting from only one Misoperation is not a failure of coordination, but an isolated setting issue.

39
In total, only 12 events (out of 151 Misoperation events, or 7.9%) were found to be internal to an entity.
Overall, that is 12 events out of 574 total events reported to Events Analysis, which is 2.1% of all events.

41

periodically where no change to a BES Element would have otherwise addressed changes to
Protection Systems due to incremental Fault current changes.
4. Requirement R3
The purpose of Requirement R3 is to require applicable entities to use the process they
developed under Requirement R1 for the development of any new or revised Protection System
settings for BES Elements, whether as a result of a Protection System Coordination Study
performed under Requirement R2 or the installation of a new BES Element with Protection
Systems. Requirement R3 provides:
R3.

Each Transmission Owner, Generator Owner, and Distribution Provider shall
utilize its process established in Requirement R1 to develop new and revised
Protection System settings for BES Elements.

As discussed above, using the Requirement R1 process helps ensures a consistent approach to the
development of accurate Protection System settings, decreases the possibility of introducing errors,
and increases the likelihood of maintaining a coordinated Protection System.
C.

Retirement of Requirements R2, R5 and R6 of PRC-001-1.1(ii)

Consistent with Commission orders to eliminate redundancies in NERC’s Reliability
Standards, 40 NERC is proposing to retire the remaining Requirements in PRC-001-1.1(ii) –
Requirements R2, R5, and R6 – as the reliability objectives of these Requirements are addressed
by the revised TOP/IRO Reliability Standards approved in Order No. 817. 41 While NERC did not
specifically intend on addressing issues related to PRC-001-1.1(ii) when revising the TOP/IRO

40

See Order Accepting with Conditions the Electric Reliability Organization’s Petition Requesting Approval
of New Enforcement Mechanisms and Requiring Compliance Filing, 138 FERC ¶ 61,193 at P 81 (2012); Electric
Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶ 61,147, 78 Fed.
Reg. 78424 (2013).

41

In Order No. 817, the Commission approved nine revised TOP/IRO Reliability Standards – IRO-001-4,
IRO-002-4, IRO-008-2, IRO-010-2, IRO-014-3, IRO-017-1, TOP-001-3, TOP-002-4, and TOP-003-3. Transmission
Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability
Standards, Order No. 817, 153 FERC ¶ 61,178 80 Fed. Reg. 73977 (2015).

42

Reliability Standards, those revisions created certain redundancies with Requirements R2, R5, and
R6 of PRC-001-1.1(ii). As such, these Requirements should be retired. The following is a
discussion of the manner in which Commission-approved Reliability Standards address
Requirements R2, R5, and R6 of PRC-001-1.1(ii).
1. PRC-001-1.1(ii), Requirement R2
The purpose of Reliability Standard PRC-001-1.1(ii), Requirement R2 is to require that, in
the event of protective relay or equipment failures that reduce system reliability, Transmission
Operators and Generator Operators: (1) notify relevant functional entities of such failures so that
the relevant entities can act accordingly to maintain reliability; and (2) take timely corrective action
to return the system to a stable state. Specifically, Requirement R2 provides:
R2.

Each Generator Operator and Transmission Operator shall notify reliability
entities of relay or equipment failures as follows:
R2.1.

If a protective relay or equipment failure reduces system reliability, the
Generator Operator shall notify its Transmission Operator and Host
Balancing Authority. The Generator Operator shall take corrective action
as soon as possible.

R2.2.

If a protective relay or equipment failure reduces system reliability, the
Transmission Operator shall notify its Reliability Coordinator and affected
Transmission Operators and Balancing Authorities. The Transmission
Operator shall take corrective action as soon as possible.

Requirements in recently approved Reliability Standards IRO-001-4, IRO‐008‐2, IRO‐
010‐2, TOP‐001‐3, and TOP‐003‐3, however, obviate the need for Requirement R2 of PRC-0011.1(ii). These TOP/IRO Reliability Standards address both the notification and corrective action
components of PRC-001-1.1(ii), Requirement R2, as follows.
Notification of Protective Relay and Equipment Failures: The data specification
Requirements in Reliability Standards TOP-003-3 and IRO-010-2 replace and improve upon the
notification requirements in PRC-001-1.1(ii), Requirement R2, as discussed below. Reliability
43

Standards TOP-003-3 and IRO-010-2 establish Requirements for the provision of information and
data needed by Transmission Operators, Balancing Authorities, and Reliability Coordinators for
reliable operations. Under those standards, the information and data that applicable functional
entities must provide to Transmission Operators, Balancing Authorities, and Reliability
Coordinators includes, among other things, “notification of current Protection System and [SPS]
status or degradation that impacts System reliability.” Such notifications would include failures
of protective relays or equipment as such failures would impact the status and be considered a
degradation of Protection Systems and SPS. 42 These data specification standards are each
discussed in turn, below.
Reliability Standard TOP-003-3 provides a mechanism for Transmission Operators and
Balancing Authorities to obtain the data needed to fulfill their operational and planning
responsibilities. TOP-003-3 consists of the following five Requirements:
•

Requirements R1 and R2 requires each Transmission Operator and Balancing Authority to
maintain a documented specification for the data necessary for the Transmission Operator
to perform its OPAs, Real-time monitoring, and RTAs, and for the Balancing Authority to
perform its analysis functions and Real-time monitoring. The data specification must
include, but is not limited to: (i) a list of data and information needed to support these
analyses, monitoring, and assessments; (ii) provisions for the notification of current
Protection System and Special Protection System status or degradation that impacts System
reliability; (iii) a periodicity for providing data; and (iv) the deadline by which the
respondent is to provide the indicated data.

•

Requirements R3 and R4 require each Transmission Operator (Requirement R3) and
Balancing Authority (Requirement R4) to distribute its data specification to the entities that
have the necessary data.

•

Requirement R5 requires each Transmission Operator, Balancing Authority, Generator
Owner, Generator Operator, Load-Serving Entity, Transmission Owner, and Distribution
Provider receiving a data specification pursuant to Requirement R3 or R4 to satisfy the
obligations of the documented data specification using: (i) a mutually agreeable format;

42

The “equipment” referenced in PRC-001-1.1(ii), Requirement R2 refer, among other things, to the
components of a Protection System, such as the voltage and current sensing devices providing inputs to protective
relays or the Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or
other interrupting devices.

44

(ii) a mutually agreeable process for resolving data conflicts; and (iii) a mutually agreeable
security protocol.
Similarly, Reliability Standard IRO-010-2 provides a mechanism for the Reliability
Coordinator to obtain the information and data it needs for reliable operations and to help prevent
instability, uncontrolled separation, or Cascading outages. IRO-010-2 consists of the following
three requirements:
•

Requirement R1 provides that the Reliability Coordinator must maintain a documented
specification for the data necessary for it to perform its OPAs, Real-time monitoring, and
RTAs. The data specification must include: (i) a list of data and information necessary to
support its performance of OPAs, Real-time monitoring, and RTAs, including non-Bulk
Electric System data and external network data; (ii) provisions for notification of current
Protection System and Special Protection System status or degradation that impacts System
reliability; (iii) a periodicity for providing data; and (iv) the deadline by which the
respondent is to provide the indicated data.

•

Requirement R2 provides that the Reliability Coordinator must distribute its data
specification to entities that have the required data.

•

Requirement R3 provides that each Reliability Coordinator, Balancing Authority,
Generator Owner, Generator Operator, Load-Serving Entity, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification must satisfy
the obligations of the documented specifications using a mutually-agreeable format,
process for resolving data conflicts, and security protocol.
The notification obligations in Requirement R2 of PRC-001.1(ii) is thus subsumed in the

data specification requirements in Reliability Standards TOP-003-3 and IRO-010-2.

For

Transmission Operators, Balancing Authorities and Reliability Coordinators to perform their
respective analyses, monitoring, and assessment responsibilities under the TOP/IRO Reliability
Standards, 43 they must receive Protection System and SPS data from Generator Operators and
Transmission Operators, among others.

For example, to perform an OPA or RTA, the

Transmission Operator and Reliability Coordinator must, by definition, consider the status and
degradation of Protection Systems and SPS/RAS such as any protective relay or equipment
43

See TOP-001-3, TOP-002-4, IRO-001-4, IRO-002-4, and IRO-008-3.

45

failures. Comparably, for a Balancing Authority to satisfy its obligations under TOP-001-3,
Requirement R11 to “monitor its Balancing Authority Area, including the status of [SPS] that
impact generation or Load, in order to maintain generation-Load-interchange balance within its
Balancing Authority Area and support Interconnection frequency,” the Balancing Authority must
be aware of the status and degradation of Protection Systems and SPS. To that end, TOP-003-3
and IRO-010-2 specifically require Transmission Operators, Balancing Authorities, and
Reliability Coordinators to obtain notifications on the status and degradation of Protection Systems
and SPS from, among others, Generator Operators and other Transmission Operators, as is
currently required under PRC-001-1.1(ii), Requirement R2. Accordingly, if there is any failure of
a protective relay or other components of a Protection System, Transmission Operators, Balancing
Authorities, and Reliability Coordinators will be notified.
Reliability Standards TOP-003-3 and IRO-010-2 improve upon PRC-001-1.1(ii),
Requirement R2 by clarifying the timing of such notifications. 44 PRC-001-1.1(ii) does not include
any time period associated with the notification, making it difficult for entities to know when to
provide the notifications from a reliability perspective and for the ERO to measure compliance
with the notification requirement.

In contrast, TOP-003-3 and IRO-010-2 require the

Transmission Operator, Balancing Authority, and Reliability Coordinator to set (i) the periodicity
for providing data, and (ii) the deadline for respondents to provide the indicated data. Applicable
entities would thus have certainty as to when the notifications must be provided and the ERO
would be able to determine whether the notification was provided in a timely manner.

44

In Order No. 693, the Commission directed NERC to determine the appropriate timeframe for the
notifications, as discussed further below. Order No. 693 at P 1445.

46

Providing Transmission Operators, Balancing Authorities, and Reliability Coordinators the
authority to set the deadlines for providing the various data helps ensure that required notifications
are provided within a timeframe designed to maintain reliable operations.

Specifically,

Transmission Operators, Balancing Authorities, and Reliability Coordinators must establish the
periodicity and deadlines in a data specifications to allow those entities to perform their functional
obligations specified in NERC’s Reliability Standards. If certain data is needed to perform an
RTA, for instance, it must be provided every 30 minutes as Reliability Coordinators and
Transmission Operators must perform RTAs every 30 minutes. 45 As RTAs, by definition, require
Reliability Coordinators and Transmission Operators to consider the status and degradation of
Protection Systems and SPS in assessing current operating conditions every 30 minutes, NERC
expects that they would require entities to provide notification of protective relay or equipment
failures within 30 minutes from the time the failure is discovered, if not sooner, and the Reliability
Coordinator and Transmission Operator will include that information in its next RTA.
Corrective Action: Commission-approved Reliability Standards TOP-001-3 and IRO-0014 more clearly address the reliability objective in PRC-001-1.1(ii), Requirement R2 of requiring
Transmission Operators and Generator Operators to take corrective action to address protective
relay and equipment failures that reduce system reliability. Pursuant to Reliability Standards TOP001-3, Requirements R1 and R2, and IRO-001-4, Requirement R1, each Transmission Operator,
Balancing Authority, and Reliability Coordinator must “act to maintain the reliability of its [area]
via direct actions or by issuing Operating Instructions.” 46 Under these Requirements, if there is
an event on the BES that reduces (or threatens to reduce) system reliability, such as protective

45

See TOP-001-3, Requirement R13, IRO-008-2, Requirement R4.

46
IRO-001-4, Requirement R1 uses the word “address,” not “maintain,” where TOP-001-3, Requirements R1
and R2 use the word “maintain.”

47

relay or equipment failures, Transmission Operators, Balancing Authorities, and Reliability
Coordinators have an affirmative obligation to take corrective action to maintain reliability,
whether by their own actions or by directing the actions of others through the issuance of an
Operating Instruction. 47 As provided in TOP-001-3, Requirements R3-R6, and IRO-001-4,
Requirements R2 and R3, any functional entity, including a Generator Operator or another
Transmission Operator, that is the subject of such an Operating Instruction must: (1) comply with
the Operating Instruction, unless such action cannot be physically implemented or it would violate
safety, equipment, regulatory, or statutory requirements; or (2) inform the entity that issued the
Operating Instruction that it cannot comply with an Operating Instruction.
The affirmative requirements for Transmission Operators, Balancing Authorities, and
Reliability Coordinators to act to maintain reliability in their area and issue Operating Instructions,
when necessary, and for entities to comply with any Operating Instructions eliminate the need for
a separate obligation such as that in PRC-001.1(ii), Requirement R2 for Generator Operators and
Transmission Operators to take corrective action to address protective relay and equipment
failures. Under the data specification requirements in Reliability Standards TOP-003-3 and IRO010-2, if a Generator Operator or Transmission Operators notifies a Balancing Authority,
Reliability Coordinator, or another Transmission Operator of a change in status or degradation of
a Protection System or RAS (including protective relay or equipment failure that would reduce
system reliability), compliance with Reliability Standards TOP-001-3 and IRO-001-4 requires the
Transmission Operator, Balancing Authority, and/or Reliability Coordinator to maintain reliability
by taking corrective action themselves or issuing an Operating Instruction to direct the notifying

47

As defined in the NERC Glossary, an Operating Instruction is “[a] command by operating personnel
responsible for the Real-time operation of the interconnected Bulk Electric System to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.”

48

Generator Operator or Transmission Operator to take specific corrective action to resolve any
operational issues resulting from the failure. If the Generator Operator or Transmission Operator
is directed to take corrective action pursuant to an Operating Instruction, the Generator Operator
or Transmission Operator must comply with those instructions according to the TOP/IRO
standards.
Additionally, pursuant to TOP-002-4, Requirement R2 and R3, IRO-008-2, Requirements
R2 and R3, if, as a result of an OPA, a Transmission Operator or Reliability Coordinator identifies
an actual or expected SOL or IROL exceedance as a result of an issue on the system, it must
develop an Operating Plan to mitigate any such exceedances and inform other functional entities
of their role in the Operating Plan. 48 If the issue on the system relates to protective relay or
equipment failures, the Operating Plan would address the corrective action necessary to mitigate
the reliability impact of those failures and identify the appropriate entity to take such action so as
to return the system to a secure and reliable state in a timely manner.
Further, pursuant to TOP-001-3, Requirement R14, each Transmission Operator must
initiate its Operating Plan to mitigate a SOL exceedance identified as part of its Real-time
monitoring or RTA. Similarly, under IRO-008-2, Requirement R5, if the results of its RTA
“indicate an actual or expected condition that results in, or could result in, a [SOL] or [IROL]
exceedance within its Wide Area,” the Reliability Coordinator must notify impacted Transmission
Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted
Reliability Coordinators as indicated in its Operating Plan.

48

See TOP-001-3, Requirement R14, TOP-002-4, Requirement R2 and R3, IRO-008-2, Requirements R2 and

R5.

49

The framework established by the TOP/IRO Reliability Standards for requiring corrective
action improves upon Requirement R2 of PRC-001-1.1(ii) by: (1) providing Reliability
Coordinators, Balancing Authorities, and Transmission Operators the authority to determine the
appropriate corrective action based on the data specifications; and (2) setting clearer expectations
for the timeframes under which the corrective action must be taken. 49 Requirement R2 of PRC001-1.1(ii) assigns the responsibility to determine the appropriate corrective action to the
Generator Operator and Transmission Operator whose protective relay or equipment failed. In
contrast to the construct in PRC-001-1.1(ii), the framework in the TOP/IRO Reliability Standards
appropriately assigns corrective actions to those functional entities in the best position to identify
the corrective actions that are necessary to return the system to a secure and reliable state.
The TOP/IRO Reliability Standards assign the responsibility to determine the appropriate
corrective actions to those functional entities – Reliability Coordinators, Balancing Authorities,
and Transmission Operators – with a wide-area view of the BES and greater understanding of the
actions necessary to return the system to a secure and reliable state. As explained above, the
TOP/IRO standards establish a framework where, under TOP-003-3 and IRO-010-2, information
and data regarding protective relay and equipment failures, among other things, are sent to those
functional entities with a broader view of BES conditions – e.g., from a Generator Operator to
Transmission Operator and Balancing Authority, and from a Transmission Operator to a Balancing
Authority, Reliability Coordinator, or other Transmission Operators. Those functional entities are
then required, pursuant to TOP-001-3, TOP-002-4, IRO-001-4, IRO-002-4, and IRO-008-2 to: (i)
monitor and analyze BES conditions with the appropriate inputs, 50 (ii) determine whether any

49

In Order No. 693, the Commission directed NERC to determine the appropriate timeframe taking
corrective action, as discussed further below. Order No. 693 at P 1441.

50

Specifically, as described above, Transmission Operators are required to: (1) perform OPAs pursuant to
TOP-002-4, Requirement R1; (2) perform RTAs every 30 minutes pursuant to TOP-001-3, Requirement R13; and

50

corrective action is necessary, 51 and (iii) either take that corrective action themselves or require
other functional entities to take that corrective action. 52 This framework improves reliability by
placing the responsibility to determine the appropriate course of action with those entities best
equipped to make those determinations through monitoring and analyzing system conditions.
Moreover, the framework established by the TOP/IRO Reliability Standards avoids the
uncertainties associated with the timing element in PRC-001-1.1(ii) that Generator Operators and
Transmission Operators take corrective action “as soon as possible.” The objective of the “as soon
as possible” language is to require entities to take corrective action on a timely basis to maintain
reliable operations without specifying a uniform (or one-size-fits-all) time period to be applied in
every instance. A uniform timeframe for corrective action is not appropriate because various
protective relays or equipment failures present different levels of risk to reliable operation.
Whereas certain failures would cause more immediate reliability issues and entities should act in
a shortened timeframe (e.g., within 30 minutes or less), other failures may not cause such
immediate risks to reliability and entities should have additional time to correct the issue.

(3) perform Real-time monitoring under TOP-001-3, Requirement R10. Similarly, Reliability Coordinators are
required to: (1) perform OPAs pursuant to IRO-008-2, Requirement R1; (2) perform RTAs every 30 minutes
pursuant to IRO-008-2, Requirement R4; and (3) perform Real-time monitoring pursuant to IRO-002-4,
Requirement R3. Balancing Authorities are also required to perform Real-time monitoring pursuant to TOP-001-3,
Requirement R11.
51

Based on the results of the OPAs, Transmission Operators are required to develop an Operating Plan for
next-day operations to address actual or expected SOL exceedances and inform entities of their role under the plan,
pursuant to TOP-002-4, Requirements R2 and R3. If the results of an RTA or Real-time monitoring indicate an
actual or expected SOL exceedance, the Transmission Operator must initiate its Operating Plan. Similarly,
Reliability Coordinators must (1) develop a coordinated Operating Plan for next-day operations to address actual or
expected SOL and IROL exceedances identified as a result of its OPA and inform entities of their role under the
plan, pursuant to IRO-008-2, Requirements R2 and R3, and (2) if its RTA indicates an actual or expected condition
that results in, or could result in, a SOL or IROL exceedance, notify impacted Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as
indicated in its Operating Plan, pursuant to IRO-008-2, Requirement R5.
52
Pursuant to Reliability Standards TOP-001-3, Requirements R1 and R2, and IRO-001-4, Requirement R1,
each Transmission Operator, Balancing Authority, and Reliability Coordinator must “act to address the reliability of
its [area] via direct actions or by issuing Operating Instructions.”

51

Nevertheless, the phrase “as soon as possible” has created certain uncertainties for entities as to
the timeframe under which they must take corrective action.
The Commission-approved TOP/IRO Reliability Standards, however, provide Reliability
Coordinators, Balancing Authorities, and Transmission Operators the authority to set the
appropriate timeframes for corrective action. If a Reliability Coordinator, Balancing Authority, or
Transmission Operator issues an Operating Instruction directing other entities to take corrective
action, the Operating Instruction would include a timeframe for such action. Similarly, if, as a
result of an OPA, a Transmission Operator or Reliability Coordinator develops an Operating Plan
to address actual or expected SOL or IROL exceedances, the Operating Plan could include the
timeframe for any corrective action. The timeframes for any corrective action may thus be known
to the entity required to take the action as well as the ERO in determining whether the applicable
entities took corrective action on a timely basis.
This construct also improves reliability by assigning the responsibility to determine the
appropriate timeframe to those functional entities with a wider view of the BES and greater
understanding of the actions necessary to return the system to a secure and reliable state. As
discussed above, Reliability Coordinators, Balancing Authorities, and Transmission Operators are
responsible for monitoring and analyzing system conditions. As a result, these entities are in the
best position to understand the appropriate timeframe for corrective action.
With the exception of IROL exceedances, the Commission-approved TOP/IRO Reliability
Standards provide these entities the flexibility to develop the timeframe for corrective action based
on their judgment of the facts and circumstances before them. As noted above, a uniform
timeframe for all corrective action is not appropriate as different reliability issues present different
levels of risks to reliable operation. Some issues require immediate attention to maintain reliability

52

while others may be addressed on a longer time horizon. Nevertheless, Reliability Coordinators,
Balancing Authorities, and Transmission Operators must set timeframes for corrective action
consistent with their obligations under the Reliability Standards to maintain reliable operation.
Should the Transmission Operator or Reliability Coordinator, for instance, identify an actual or
expected SOL exceedance, they must develop and initiate a coordinated Operating Plan to mitigate
the SOL exceedance that include timeframes for corrective action to mitigate a SOL exceedance.
Although the TOP standards do not specify a timeframe by which Transmission Operators must
mitigate SOL exceedances (that are not also IROL exceedances), the Transmission Operator must
take action or direct others to take action on a timely basis or it could potentially violate its
obligation to maintain reliability in its area (TOP-001-3, Requirement R1).
For IROL exceedances, TOP standards specifically require corrective action within 30
minutes. Reliability Standard TOP-001-3, Requirement R12 prohibits Transmission Operators
from “operat[ing] outside any identified [IROL] for a continuous duration exceeding its associated
IROL Tv,” which is not to exceed 30 minutes. Accordingly, if a protective relay or equipment
failure would cause an IROL exceedance, the Transmission Operator must take corrective action
itself, or issue an Operating Instruction to another entity to take corrective action, within 30
minutes, if not sooner, or else the Transmission Operator would potentially violate TOP-001-3,
Requirement R12.
2. PRC-001-1.1(ii), Requirement R5
The reliability objective of Requirement R5 of PRC-001-1.1(ii) to coordinate changes in
generation, transmission, load or operating conditions that could require changes in the Protection
Systems of others is now primarily addressed by Reliability Standard TOP-003-3, as well as
Reliability Standards TOP-001-3, TOP-002-4, IRO-008-2, IRO-010-2, and IRO-017-1.

53

As

discussed further below, these Reliability Standards collectively require coordination and analysis
of changes in system conditions that would necessitate changes to, among other things, the
Protection Systems of others.
Requirement R5 of PRC-001-1.1(ii) provides:
R5.

A Generator Operator or Transmission Operator shall coordinate changes in
generation, transmission, load or operating conditions that could require changes
in the Protection Systems of others:
R5.1. Each Generator Operator shall notify its Transmission Operator in
advance of changes in generation or operating conditions that could
require changes in the Transmission Operator’s Protection Systems.
R5.2. Each Transmission Operator shall notify neighboring Transmission
Operators in advance of changes in generation, transmission, load, or
operating conditions that could require changes in the other Transmission
Operators’ Protection Systems.

Given the scope of Commission-approved Reliability Standard TOP-003-3, however, there
is no longer a reliability need for a separate Requirement in PRC-001.1(ii) to address advanced
notification of changes in generation, transmission, load or operating conditions that could require
changes in the Protection Systems of others. As further described above, TOP-003-3 provides a
mechanism for Transmission Operators to obtain the data needed to fulfill their operational and
planning responsibilities, including the data needed to support their OPAs, Real-time monitoring,
and RTAs. Among other things, a Transmission Operator must receive data from other entities
regarding changes in generation, transmission, load, or operating conditions that could affect its
system, including any such changes that may necessitate modifications to its Protection Systems
or RAS.
Without such data, a Transmission Operator cannot perform an OPA, consistent with TOP002-4, to effectively projects system conditions to assess anticipated (pre-Contingency) and
potential (post-Contingency) conditions for next-day operations. Similarly, without such data, a
54

Transmission Operator cannot perform an RTA, consistent with TOP-001-3, to effectively assess
existing (pre-Contingency) and potential (post-Contingency) operating conditions.

A

Transmission Operator must thus include in its data specifications a requirement that other entities,
such as Generator Operators and other Transmission Operators, provide notice of any changes in
generation, transmission, load, or operating conditions that may necessitate changes to its
Protection Systems or RAS.

NERC anticipates that, as part of its OPAs and RTAs, the

Transmission Operator would, where necessary, verify whether any of the changes noted by
Generator Operators or other Transmission Owners necessitate changes to its Protection Systems
and RAS in order to maintain reliable operation.

If any such changes are necessary, the

Transmission Operator would include them in its Operating Plan or otherwise make the necessary
changes to the Protection Systems or RAS to satisfy its obligation under TOP-001-3, Requirement
R1 to take action to maintain reliability in its area.
Additionally, the data specification requirements in IRO-010-2 and the obligations in IRO008-2 that Reliability Coordinators perform OPAs and develop coordinated Operating Plans,
where necessary, further the reliability objective of Requirement R5 of PRC-001.1(ii) by including
coordination with the next-day Operating Plans provided by Transmission Operators and
Balancing Authorities.

Like the Transmission Operator, the Reliability Coordinator has an

obligation to evaluate system conditions in the day-ahead timeframe (i.e., OPAs) and in Real-time
(i.e., RTAs) pursuant to IRO-008-2 and obtain data from other functional entities to perform those
evaluations pursuant to IRO-010-2. Under these standards, the Reliability Coordinator must
receive data on changes to generation, transmission, load or operating conditions and evaluate, via
OPAs and RTAs, whether any action is necessary to maintain reliability, including making changes
to Protection Systems and RAS.

55

The outage coordination requirements of IRO-017-1 also enhance coordination between
functional entities. Reliability Standard IRO-017-1 (Outage Coordination) is a new Reliability
Standard designed to ensure that outages are properly coordinated in the operations planning time
horizon and Near-Term Transmission Planning Horizon.

The Reliability Coordinator must

establish an outage coordination process that, among other things, provides for the communication
of outage schedules, assignment of coordination responsibilities, and evaluation of the impact of
transmission and generation outages. The process helps identify whether any outages necessitate
changes in Protection Systems or RAS. Outage information is also an input to OPAs and RTAs.
3. PRC-001-1.1(ii), Requirement R6
Pursuant to PRC-001-1.1(ii), Requirement R6, Transmission Operators and Balancing
Authorities must monitor the status of each SPS in their area and notify affected Transmission
Operators and Balancing Authorities of any change in status. This reliability objective is now
addressed in approved Reliability Standards TOP-001-3 and TOP-003-3, making a separate
requirement in PRC-001-11(ii) unnecessary. Specifically, Requirements R10 and R11 of TOP001-3 create an affirmative obligation for Transmission Operators and Balancing Authorities to
monitor the status of SPS. Specifically, TOP-001-3, Requirements R10 and R11 provide as
follows:
R10.

R11.

Each Transmission Operator shall perform the following as necessary for
determining [SOL] exceedances within its Transmission Operator Area:
10.1.

Within its Transmission Operator Area, monitor Facilities and the status of
Special Protection Systems, and

10.2.

Outside its Transmission Operator Area, obtain and utilize status, voltages,
and flow data for Facilities and the status of Special Protection Systems.

Each Balancing Authority shall monitor its Balancing Authority Area, including
the status of Special Protection Systems that impact generation or Load, in order
to maintain generation-Load-interchange balance within its Balancing Authority
Area and support Interconnection frequency.
56

The Commission-approved IRO standards also improve upon Requirement R6 of PRC001-1.1(ii) by requiring the Reliability Coordinator to monitor the status of SPS. Specifically,
IRO-002-4, Requirement R3 provides:
R3.

Each Reliability Coordinator shall monitor Facilities, the status of Special
Protection Systems, and non-BES facilities identified as necessary by the
Reliability Coordinator, within its Reliability Coordinator Area and neighboring
Reliability Coordinator Areas to identify any System Operating Limit exceedances
and to determine any Interconnection Reliability Operating Limit exceedances
within its Reliability Coordinator Area.

With respect to the notification element of Requirement R6 of PRC-001-1.1(ii), the data
specification Requirements in TOP-003-3 and IRO-010-2 require entities to provide “notification
of current Protection System and Special Protection System status or degradation that impacts
System reliability.” A separate requirement in PRC-001-1.1(ii) requiring these notifications is
therefore unnecessary.
D.

Resolution of Outstanding Commission Directives Related to PRC-001-1.1(ii)

In Order No. 693, the Commission approved Reliability Standard PRC-001-1 and also
issued certain directives related to the meaning of the phrases “corrective action” and “as soon as
possible” in Requirement R2.

53

Accordingly, the scope of Project 2007-06.2 included

consideration of outstanding Commission directives from Order No. 693 related to PRC-0011.1(ii). The following is a description of each of the Commission’s outstanding directives and a
discussion of the manner in which the TOP/IRO Reliability Standards approved in Order No. 817
address each of those directives.
Clarifying the Term Corrective Action: In Order No. 693, paragraphs 1439-1441, the
Commission directed NERC to clarify that the term “corrective action” refers to “transmission

53

Order No. 693 at PP 1433-49.

57

operators taking operator control actions” and “does not refer to troubleshooting, repairing or
replacing failed relays or equipment” performed by field maintenance personnel. 54 As discussed
above, NERC proposes to retire Requirement R2 of PRC-001-1.1(ii) as the new TOP/IRO
standards address, in a more precise fashion, the reliability objective of requiring Transmission
Operators and Generator Operators to take corrective action following protective relay or
equipment failures. Pursuant to Reliability Standards TOP-001-3, Requirements R1 and R2, and
IRO-001-4, Requirement R1, each Transmission Operator, Balancing Authority, and Reliability
Coordinator must “act to maintain the reliability of its [area] via direct actions or by issuing
Operating Instructions.”

The focus on action “to maintain [] reliability” and Operating

Instructions, which is defined as a “command by operating personnel responsible for Real-time
operation…to change or preserve the state, status, output, or input” of an Element or Facility of
the BES, clarifies that the required action relates to operator control actions done on a timely basis
to support reliable operations, not long-term action such as replacing failed relays and equipment.
Time for Corrective Action: In paragraphs 1444-1445 and 1449 of Order No. 693, the
Commission discussed the appropriate timeframe for “corrective action” and directed NERC to
develop a modification to PRC-001 to clarify the timeframe for taking corrective action. The
Commission stated that the requirement for System Operators to take corrective action when
protective relay or equipment failure reduces system reliability should be treated the same as the
requirement for returning a system to a secure and reliable state after an IROL violation, i.e., as
soon as possible, but no longer than 30 minutes after a violation as a longer time limit would place
an entity in violation of relevant IROL or TOP Reliability Standards. 55 As discussed above, the

54

Order No. 693 at PP 1439-41. Operator control actions include removing the facility without protection
from service, generation re-dispatch, transmission re-configuration, etc.
55

Id. at PP 1443, 1449.

58

timeframes for corrective action when protective relay or equipment failure reduces system
reliability are now addressed in the TOP/IRO standards. Those standards, as approved by
Commission, provide Reliability Coordinators, Balancing Authorities, and Transmission
Operators the authority to set the appropriate timeframes for corrective action, although those
timeframes must be consistent with their other requirements, including their affirmative obligation
to maintain reliability in their area and not to operate outside of an IROL for longer than 30
minutes.
Timeframe for Notification of Failures: The Commission also directed NERC to modify
the standard to determine a timeframe under which Generator Operators and Transmission
Operators must provide the notifications of protective relay or equipment failures. 56 As discussed
above, the timeframe for these notifications is now established in the data specifications required
in TOP-003-3 and IRO-010-2. The periodicity and deadlines in the Transmission Operator’s,
Balancing Authority’s, and Reliability Coordinator’s data specifications must be set to allow those
entities to perform their functional obligations. For instance, if certain data, such as the status of
Protection Systems and RAS, is needed to perform an RTA, it must be provided every 30 minutes
as Reliability Coordinators and Transmission Operators must perform RTAs every 30 minutes. 57
PRC-001 Measures and VSLs: The Commission directed NERC to correct certain
references in the Measures and VSLs to non-existent requirements. 58 As NERC proposes the
retirement of PRC-001-1.1(ii), there is no need to correct these references.

56

Id. at P 1449.

57

The TOP/IRO standards also address the comments of the California Public Utilities Commission as
directed by the Commission at Order No. 693 at P 1444.
58
Id. at P 1446.

59

E.

Enforceability of the Proposed Reliability Standards

The proposed Reliability Standards include VRFs and VSLs. The VRFs and VSLs provide
guidance on the way that NERC will enforce the requirements of the proposed Reliability
Standards. The VRFs and VSLs for the proposed Reliability Standards comport with NERC and
Commission guidelines related to their assignment. Exhibit F provides a detailed review of the
VRFs and VSLs, and the analysis of how the VRFs and VSLs were determined using these
guidelines.
The proposed Reliability Standards also include measures that support each requirement
by clearly identifying what is required and how the ERO will enforce the requirement. These
measures help ensure that the requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. 59
V.

EFFECTIVE DATE
NERC respectfully requests that the Commission approve the proposed Reliability

Standards and definitions, and the retirement of PRC-001-1.1(ii) to become effective as set forth
in the proposed Implementation Plans, provided in Exhibit B hereto.

The proposed

Implementation Plans for proposed Reliability Standards PER-006-1 and PRC-027-1, provided in
Exhibit B hereto, provide that the proposed standards and definitions shall become effective on
the first day of the first calendar quarter that is 24 months following the effective date of the
Commission’s order approving the standards. The 24-month implementation period will provide
applicable entities sufficient time to (1) develop the training program required under proposed
PER-006-1, (2) integrate the functions and limitations of Protection Systems and RAS into their
OPAs and RTAs, and (3) develop and implement the process required by proposed PRC-027-1.

59

Order No. 672 at P 327.

60

Applicable entities need to devote considerable resources to the development of the program and
process required by the proposed standards and, in turn, require substantial lead time prior to
implementation.
During the 24-month implementation period, entities must continue to comply with the
Requirements in PRC-001-1.1(ii) until the proposed standards become effective, with the
exception of Requirements R2, R5 and R6. Those Requirements, which, as discussed above, are
being replaced by the TOP/IRO standards approved in Order No. 817, are proposed to be retired
on March 31, 2017. The new TOP/IRO standards become effective on April 1, 2017.
VI.

CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•

the proposed Reliability Standards and associated elements included in Exhibit A,
effective as proposed herein;

•

the proposed Implementation Plans included in Exhibit B;

•

the proposed new and revised definitions to be incorporated into the NERC Glossary
included in Exhibit A; and

•

the retirement of Commission-approved Reliability Standard PRC-001-1.1(ii),
effective as proposed herein.
Respectfully submitted,
/s/ Shamai Elstein
Charles A. Berardesco
Senior Vice President and General Counsel
Shamai Elstein
Senior Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
202-400-3000
charles.berardesco@nerc.net
shamai.elstein@nerc.net
Counsel for the North American Electric Reliability Corporation

Date: September 2, 2016
61