NERC Petition to approve PRC-023-2

NERC Petition on PRC-023-2 on 3-18-11.pdf

FERC-725G, [Final Rule in RM11-16-000) Transmission Relay Loadability Mandatory Reliability Standard for the Bulk Power System

NERC Petition to approve PRC-023-2

OMB: 1902-0252

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March 18, 2011
VIA ELECTRONIC FILING
Ms. Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, D.C. 20426
Re:

North American Electric Reliability Corporation,
Docket No. RM08-13-000

Dear Ms. Bose:

The North American Electric Reliability Corporation (“NERC”) hereby submits this
petition in accordance with Section 215(d)(1) of the Federal Power Act (“FPA”) and Part 39.5
of the Federal Energy Regulatory Commission’s (“FERC”) regulations and in compliance with
directives in FERC Order No. 733 1 seeking approval of the following proposed Protection and
Control (PRC) Reliability Standard set forth as Exhibit A to this petition that was approved by
the NERC Board of Trustees on March 10, 2011:
•

PRC-023-2 – Transmission Relay Loadability (PRC-023-2).

NERC also requests FERC approval of the associated implementation plan for the proposed
PRC-023-2 standard that establishes effective dates for each requirement as set out in section 5
– Effectives Dates of the PRC-023-2 Reliability Standard.
Additionally, NERC was directed in Order No. 733 to develop a process by which
entities could challenge criticality determinations made by the Planning Coordinators under the

Transmission Relay Loadability Reliability Standard. 130 FERC ¶ 61,221. (2010) (“Order No. 733”).

proposed PRC-023-2. 2 To address this directive, NERC is including with this filing for FERC
approval a proposed addition to the NERC Rules of Procedure, Section 1700 – Challenges to
Determinations.
This filing discusses the proposed PRC-023-2 Reliability Standard, including how the
proposed standard and associated implementation plan meet the criteria identified by FERC in
Order No. 672 3 for approving Reliability Standards.
This filing consists of the following:
•

This transmittal letter;

•

A table of contents;

•

A narrative description explaining how the proposed PRC-023-2 Reliability
Standard meets FERC’s requirements;

•

The proposed PRC-023-2 Reliability Standard submitted for approval (Exhibit A);

•

The associated Implementation Plan for the proposed PRC-023-2 Reliability
Standard submitted for approval (Exhibit B);

•

The Standard Drafting Team Roster for Project 2010-13 Relay Loadability Order
733 (Exhibit C);

•

The Mapping Document for Project 2010-13 Relay Loadability Order 733 Standard
(Exhibit D);

•

Proposed NERC Rules of Procedure Section 1700 – Challenges to Determinations
(Exhibit E); and

•

The Development Record of the proposed PRC-023-2 Reliability Standard and the
associated Implementation Plan (Exhibit F).

Please contact me if you have any questions regarding this filing.
Respectfully submitted,
/s/ Holly A. Hawkins
Holly A. Hawkins
Attorney for North American
Electric Reliability Corporation
2

Order No. 733 at P. 97.
See Rules Concerning Certification of the Electric Reliability Organization; Procedures for the Establishment,
Approval and Enforcement of Electric Reliability Standards, FERC Stats. & Regs., ¶ 31,204 at PP 320-338 (“Order
No. 672”), order on reh’g, FERC Stats. & Regs. ¶ 31,212 (2006) (“Order No. 672-A”).

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

) Docket No. RM08-13-000
)

PETITION OF THE NORTH AMERICAN ELECTRIC RELIABILITY
CORPORATION FOR APPROVAL OF A PROTECTION AND CONTROL
(PRC) RELIABILITY STANDARD
Gerald W. Cauley
President and Chief Executive Officer
David N. Cook
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
116-390 Village Boulevard
Princeton, NJ 08540-5721
(609) 452-8060
(609) 452-9550 – facsimile
david.cook@nerc.net

Holly A. Hawkins
Assistant General Counsel for Standards
and Critical Infrastructure Protection
North American Electric Reliability
Corporation
1120 G Street, N.W.
Suite 990
Washington, D.C. 20005-3801
(202) 393-3998
(202) 393-3955 – facsimile
holly.hawkins@nerc.net

March 18, 2011

TABLE OF CONTENTS
I.

Introduction

II.

Notices and Communications

III.

Background:

a. Regulatory Framework

b. Basis for Approval of Proposed Reliability Standard

c. Reliability Standards Development Procedure

IV. Justification for Approval of the Proposed Reliability Standard

Request for FERC approval of Proposed NERC Rules of
Procedure Section 1700—Challenges to Determinations

VI. Summary of the Reliability Standard Development Proceedings

VII. Conclusion

Exhibit A — Proposed PRC-023-2 Reliability Standard submitted for approval
Exhibit B — Implementation Plan for PRC-023-2 submitted for approval
Exhibit C — Standard Drafting Team Roster for Project 2010-13 Relay Loadability Order
733
Exhibit D — Mapping Document for the proposed PRC-023-2 Reliability Standard
Exhibit E — Proposed NERC Rules of Procedure Section 1700 – Challenges to
Determinations
Exhibit F — Development Record of the proposed PRC-023-2 Reliability Standard

INTRODUCTION
The North American Electric Reliability Corporation (“NERC”) 1 hereby requests the

Federal Energy Regulatory Commission (“FERC”) to approve, in accordance with Section
215(d)(1) of the Federal Power Act (“FPA”) 2 and Section 39.5 of FERC’s regulations, 18 C.F.R.
§ 39.5 the following Reliability Standard:
•

PRC-023-2 – Transmission Relay Loadability (PRC-023-2).

NERC also requests FERC approval of a proposed addition to the NERC Rules of Procedure,
Section 1700 – Challenges to Determinations. This filing satisfies certain directives the
Commission issued in Order No. 733 pertaining to developing modifications to PRC-023-1 to:
•

apply an “add in” approach to sub-100 kV facilities that are owned or operated by
currently-Registered Entities or entities that become Registered Entities in the future, and
are associated with a facility that is included on a critical facilities list defined by the
Regional Entity (P.60);

•

modify Requirement R3 of the Reliability Standard to specify the test that planning
coordinators must use to determine whether a sub-200 kV facility is critical to the
reliability of the Bulk-Power System (P. 69);

•

develop an appeals process (or point to a process in its existing procedures) for entities to
challenge criticality determinations (P 97);

•

require that transmission owners, generator owners, and distribution providers give their
transmission operators a list of transmission facilities that implement sub-requirement
R1.2 (P. 186);

•

modify sub-requirement R1.10 so that it requires entities to verify that the limiting piece
of equipment is capable of sustaining the anticipated overload for the longest clearing
time associated with the fault (P. 203);

•

provide the ERO with information to document and to make available for review to users,
owners and operators of the Bulk-Power System, by request, a list of those facilities that
have protective relays set pursuant sub-requirement R1.12 (P. 224);

•

add the Regional Entity to the list of entities that receive the critical facilities list from the
Planning Coordinator (P. 237);

NERC has been certified by FERC as the electric reliability organization (“ERO”) authorized by Section 215 of the
Federal Power Act. FERC certified NERC as the ERO in its order issued July 20, 2006 in Docket No. RR06-1-000.
116 FERC ¶ 61,062 (2006) (“ERO Certification Order”).
2
16 U.S.C. 824o.

•

include section 2 of Attachment A in the modified Reliability Standard as an additional
Requirement with the appropriate violation risk factor and violation severity level (P.
244);

•

revise section 1 of Attachment A to include supervising relay elements on the list of
relays and protection systems that are specifically subject to the Reliability Standard (P.
264);

•

include an implementation plan for sub-100 kV facilities (P. 283); and

•

remove the exceptions footnote from the “Effective Dates” section (P. 284).
The NERC Board of Trustees approved the proposed Reliability Standard on March 10,

2011, and recommended it be added to the set of approved NERC Reliability Standards. In this
filing, NERC requests FERC approval of the proposed PRC-023-2 Reliability Standard, the
associated implementation plan, and the proposed NERC Rules of Procedure Section 1700 –
Challenges to Determinations.
Exhibit A to this filing sets forth the proposed Reliability Standard in both clean and
redlined format. Exhibit B contains the Implementation Plan for PRC-023-2 which is submitted
herein for approval. Exhibit C contains the Standard Drafting Team Roster for Project 2010-13
Relay Loadability Order 733 which was responsible for drafting the proposed PRC-023-2
standard and associated Implementation Plan. Exhibit D contains the Mapping Document that
shows the changes made to the approved PRC-023-1 Reliability Standard to address the
Commission’s directives in Order 733 that resulted in the proposed PRC-023-2 Reliability
Standard. Exhibit E contains the proposed NERC Rules of Procedure Section 1700 –
Challenges to Determinations. Exhibit F contains the development record for the proposed
PRC-023-2 Reliability Standard.
NERC is also filing the proposed PRC-023-2 Reliability Standard and associated
documents with applicable governmental authorities in Canada.

II.

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

following:
Gerald W. Cauley
President and Chief Executive Officer
David N. Cook*
Senior Vice President and General Counsel
North American Electric Reliability Corporation
116-390 Village Boulevard
Princeton, NJ 08540-5721
(609) 452-8060
(609) 452-9550 – facsimile
david.cook@nerc.net

Holly A. Hawkins*
Assistant General Counsel for Standards
and Critical Infrastructure Protection
North American Electric Reliability
Corporation
1120 G Street, N.W.
Suite 990
Washington, D.C. 20005-3801
(202) 393-3998
(202) 393-3955 – facsimile
holly.hawkins@nerc.net

*Persons to be included on FERC’s service list are
indicated with an asterisk.

III.

BACKGROUND
a. Regulatory Framework
3

By enacting the Energy Policy Act of 2005, Congress entrusted FERC with the duties of
approving and enforcing rules to ensure the reliability of the Nation’s bulk power system, and
with the duties of certifying an Electric Reliability Organization (ERO) that would be charged
with developing and enforcing mandatory Reliability Standards, subject to FERC approval.
Section 215 states that all users, owners and operators of the bulk power system in the United
States will be subject to the FERC-approved Reliability Standards.
The principal purpose of the proposed PRC-023-2 Reliability Standard is to ensure that
protective relay settings will not limit transmission loadability; not interfere with system
operators’ ability to take remedial action to protect system reliability; and be set to reliably detect
all fault conditions and protect the electrical network from these faults. The requirements of the
3

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

PRC-023-2 Reliability Standard also will assure that the Planning Coordinators have a consistent
methodology to perform assessments of the Bulk Electric System to determine the circuits for
which a failure to assure adequate relay loadability could result in cascading outages similar to
what occurred during the August 2003 blackout.
b. Basis for Approval of Proposed Reliability Standard
Section 39.5(a) of FERC’s regulations requires the ERO to file with FERC for its
approval each Reliability Standard that the ERO proposes to become mandatory and enforceable
in the United States, and each modification to an approved Reliability Standard that the ERO
proposes to be made effective. FERC has the regulatory responsibility to approve standards that
protect the reliability of the bulk power system. In discharging its responsibility to review,
approve, and enforce mandatory Reliability Standards, FERC is authorized to approve those
proposed Reliability Standards that meet the criteria detailed by Congress:
The Commission may approve, by rule or order, a proposed reliability standard
or modification to a reliability standard if it determines that the standard is just,
reasonable, not unduly discriminatory or preferential, and in the public interest. 4
When evaluating proposed Reliability Standards, FERC is required by statute to give
“due weight” to the technical expertise of the ERO. Section 215(d)(2) of the Federal Power Act
requires that the Commission “give due weight to the technical expertise of the Electric
Reliability Organization with respect to the content of a proposed standard or modification to a
reliability standard.” 5 Additionally, in Order No. 693, the Commission noted that it would defer
to the “technical expertise” of the ERO with respect to the content of a Reliability Standard. 6
The Commission stated:
4

Section 215(d)(2) of the FPA, 16 U.S.C. § 824o(d)(2) (2000).
U.S.C. Section 824o (2010).
6
Mandatory Reliability Standards for the Bulk-Power System, 118 FERC ¶ 61,218, FERC Stats. & Regs. ¶ 31,242
(2007) (“Order No. 693”) at P 9, Order on Reh’g, Mandatory Reliability Standards for the Bulk-Power System, 120
FERC ¶ 61,053 (“Order No. 693-A”) (2007).
5

Pursuant to Section 215(d)(2) of the FPA and § 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 or to a Regional Entity organized on an
Interconnection-wide basis with respect to a proposed Reliability Standard or a proposed
modification to a Reliability Standard to be applicable within that Interconnection.
Order No. 672 provides guidance on the fifteen factors FERC will consider when
determining whether proposed Reliability Standards meet the statutory criteria. 7
The proposed PRC-023-2 Reliability Standard serves the important reliability goal of
specifying that protective relay settings shall not limit transmission loadability; not interfere with
system operators’ ability to take remedial action to protect system reliability and; be set to
reliably detect all fault conditions and protect the electrical network from these faults.
The proposed PRC-023-2 Reliability Standard improves reliability by:
•

assuring that protective relay settings do not limit transmission loadability; do not
interfere with system operators’ ability to take remedial action to protect system
reliability; and are set to reliably detect all fault conditions and protect the electrical
network from these faults;

•

providing awareness to entities regarding use of various criteria for verifying relay
loadability (i.e., when the relay loadability calculated circuit capability is used as the
Facility Rating of the circuit, when the relay loadability has been verified based on the
highest seasonal 15-minute Facility Rating, and when the desired transmission line
capability is limited by the requirement to adequately protect the transmission line, and

•

assuring consistent identification of circuits operated below 200 kV for which responsible
entities must comply with this standard by the defining criteria in Attachment B that will
be applied consistently by each Planning Coordinator to determine the circuits in its
Planning Coordinator area that potentially could, if they trip due to relay loadability
following an initiating event, contribute to undesirable system performance similar to
what occurred during the August 2003 blackout.
c. Reliability Standards Development Procedure
NERC develops Reliability Standards in accordance with Section 300 (Reliability

Standards Development) of its Rules of Procedure and the NERC Standard Processes Manual,
7

Rules Concerning Certification of the Electric Reliability Organization; Procedures for the Establishment,
Approval and Enforcement of Electric Reliability Standards, FERC Stats. & Regs., ¶ 31,204 at PP 320-338 (“Order
No. 672”) at PP 320-338, Order on Reh’g, FERC Stats. & Regs. ¶ 31,212 (2006) (“Order No. 672-A”).

which is included in the NERC Rules of Procedure as Appendix 3A. 8 In its ERO Certification
Order, FERC 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. 9
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 and a
vote of stakeholders and the NERC Board of Trustees is required to approve a Reliability
Standard for submission to FERC.
The NERC Standards Committee initiated Project 2010-13 Relay Loadability Order 733
to address the directives identified in FERC Order No. 733. Relay loadability issues were
brought to light by the investigation of the August 14, 2003 blackout, where it was noted that
they were either causal or contributory to many of the major electric system disturbances dating
back to the 1965 blackout. 10 The PRC-023 – Transmission Relay Loadability Reliability
Standard was developed with the purpose of assuring that protective relay settings do not cause
premature tripping due to relay loadability when circuits are operating within their capability,
thereby limiting transmission loadability; do not interfere with system operators’ ability to take
remedial action to protect system reliability; and reliably detect all fault conditions and protect
the electrical network from these faults.

FERC approved the new Reliability Standard Processes Manual on September 3, 2010 (FERC Docket No. RR1012-000), which replaces the previous FERC-approved Reliability Standards Development Procedure Version 7 in its
entirety. NERC’s Reliability Standards Development Procedure is available on NERC’s website at
http://www.nerc.com/fileUploads/File/Standards/RSDP_V6_1_12Mar07.pdf. NERC developed this standard in
accordance with the Reliability Standards Development Procedure Version 7 until the Standard Processes Manual
was approved on September 3, at which time that procedure was used to complete development of the proposed
standard.
9
Order No. 672 at PP 268, 270.
10
See, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and
Recommendations, U.S.-Canada Power System Outage Task Force, April 5, 2004.

Because relay loadability is not influenced by geographic variations, regional variations
in the organizational and corporate structures of transmission owners and operators, variations in
generation fuel type and ownership patterns, or regional variations in market design, the
Transmission Relay Loadability requirements must be applied uniformly throughout North
America, with no exceptions. The proposed Transmission Relay Loadability Reliability
Standard has been written to establish mandatory criteria that will be applied consistently by
each Planning Coordinator to determine the circuits in its Planning Coordinator area for which
Transmission Owners, Generator Owners, and Distribution Providers must comply with the
standard. These criteria, included in Attachment B of the standard, assure that all Planning
Coordinators will use comprehensive and rigorous criteria that are consistent across all regions to
avoid vulnerability to similar problems that resulted in the cascade during the August 2003
blackout and other system disturbances.
Accordingly, the Standards Committee sought out highly talented and experienced
candidates from industry to modify the PRC-023-1 — Transmission Relay Loadability (PRC023-1) standard in response to FERC Order No. 733. The team that was formed consisted of 17
highly qualified industry stakeholders and four subject matter experts from NERC. The existing
Relay Loadability drafting team was reconvened to address the directed modifications to the
standard which resulted in the development of the proposed PRC-023-2 standard. The drafting
team was assisted by a Blue Ribbon Panel that was formed to develop the criteria that would be
consistently applied by the Planning Coordinator to determine the circuits in its Planning
Coordinator area for which Transmission Owners, Generator Owners, and Distribution Providers
must comply with the standard. The drafting team and Blue Ribbon Panel consisted of members
that each have on average about 30 years of extensive industry experience in transmission

planning, operations planning, real-time operations, application of protective relaying to the
transmission and distribution systems, power system dynamics modeling and simulation,
performance assessment, and policy development. Many of these people work or have worked
for a variety of investor-owned utilities and regional entities, while others have also taught the
industry at the university level. The credentials of the drafting team members are exemplary,
many with advanced degrees, and the majority of which are members, senior members, or
fellows of IEEE or other technical industry bodies.
The work culminating in this filing originated from the directives in FERC Order No.
733. 11 In Order No. 733, the Commission approved NERC’s petition for the approval of PRC023-1 and directed NERC to modify the PRC-023-1 standard through its Reliability Standards
development process, to be completed by specific deadlines, and directed NERC to develop
requirements to address issues related to Relay Loadability. The Order also directed
development of two new Reliability Standards to address issues related to generator relay
loadability and the operation of protective relays due to power swings. The following is a
summary of the FERC directives from Order No. 733:

•

P. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.

•

Transmission Relay Loadability Reliability Standard. 130 FERC ¶ 61,221. (2010) (“Order No. 733”).

•

P. 105 . . . In light of the ERO’s statement that within two years it expects to submit to
the Commission a proposed Reliability Standard addressing generator relay loadability,
we direct the ERO to submit to the Commission an updated and specific timeline
explaining when it expects to develop and submit this proposed Standard.

•

P. 108 . . . the ERO consider whether a generic rating percentage can be established for
generator step-up transformers and, if so, determine that percentage.

•

P. 150 . . . because both NERC and the Task Force have identified undesirable relay
operation due to stable power swings as a reliability issue, we direct the ERO to develop
a Reliability Standard that requires the use of protective relay systems that can
differentiate between faults and stable power swings and, when necessary, phases out
protective relay systems that cannot meet this requirement.

•

P 162 . . . consider “islanding” strategies that achieve the fundamental performance for
all islands in developing the new Reliability Standard addressing stable power swings.

•

P. 186 . . . require that transmission owners, generator owners, and distribution providers
give their transmission operators a list of transmission facilities that implement subrequirement R1.2.

•

P. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of entities
that receive the critical facilities list. [sub-requirement R3.3]

•

P. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.

•

P. 264 . . . revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the Reliability
Standard.

•

P. 283 . . . modify the Reliability Standard to include an implementation plan for sub-100
kV facilities.

•

P. 284 . . . remove the exceptions footnote from the “Effective Dates” section.

Additionally, in Order No. 733, NERC was directed to file a report no later than 120 days
of the Order addressing the issue of protective relay operation due to stable power swings, and
was directed to include an action plan and timeline that explains how and when NERC intends to
address this issue through its Reliability Standards Development Process. NERC submitted a
Compliance Filing 12 on July 16, 2010 that includes an action plan and timeline to address the
Order No. 733 directives. Exhibit A of the Compliance Filing identifies the phased approach
that NERC is taking to address all of the directives from FERC Order No. 733. The three phases
are:
•

Phase I – Directed modifications to PRC-023, Transmission Relay Loadability

•

Phase II – Development of a new Standard Addressing Generator Relay Loadability

•

Phase III - Development of a new Standard Addressing the Issue of Protective Relay
Operations Due to Power Swings
The proposed PRC-023-2 Reliability Standard addresses FERC’s Order No. 733

directives directly related to PRC-023 in Phase I. The directives addressed in Phase I and the
changes made to the standard to address these directives are:
•

P. 60 . . . modify PRC-023-1 to apply an “add in” approach to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that become Registered
Entities in the future, and are associated with a facility that is included on a critical
facilities list defined by the Regional Entity.
The drafting team addressed this directive by adding the criteria defined in Attachment B
that will be applied consistently by each Planning Coordinator to determine the circuits in
its Planning Coordinator area for which Transmission Owners, Generator Owners, and
Distribution Providers must comply with the standard.

•

See, Compliance Filing of the North American Electric Reliability Corporation in Response to FERC Order No.
733, Docket No. RM08-13-000 (March 18, 2010).

The drafting team also addressed this directive with the criteria defined in Attachment B.
The same criteria will be used by the Planning Coordinator for evaluating circuits
operated at 100 kV to 200 kV as for circuits operated below 100 kV.
•

P. 97 . . . there should be some mechanism for entities to challenge criticality
determinations. We agree that such a mechanism is appropriate and direct the ERO to
develop an appeals process (or point to a process in its existing procedures) and submit it
to the Commission no later than one year after the date of this Final Rule.
NERC addressed this directive by developing the proposed NERC Rules of Procedure
Section 1700 – Challenges to Determinations. Section 1700 provides an appeals process
for challenging criticality determinations made by Planning Coordinators under the
proposed PRC-023-2 Reliability Standard.

•

P. 186 . . . require that transmission owners, generator owners, and distribution providers
give their transmission operators a list of transmission facilities that implement subrequirement R1.2.
The drafting team addressed this directive by adding a new Requirement R4 that requires
each Transmission Owner, Generator Owner, and Distribution Provider to provide its
Planning Coordinator, Transmission Operator, and Reliability Coordinator with an
updated list of circuits that implement Requirement R1, criterion 2.

•

P. 203 . . . modify sub-requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated overload for the
longest clearing time associated with the fault.
The drafting team addressed this directive by modifying Requirement R1, criterion 10 to
include sub-requirement 10.1 that requires entities to set load responsive transformer fault
protection relays, if used, such that the protection settings do not expose the transformer
to a fault level and duration that exceed the transformer’s mechanical withstand
capability.

•

P. 224… direct the ERO to document, subject to audit by the Commission, and to make
available for review to users, owners and operators of the Bulk-Power System, by
request, a list of those facilities that have protective relays set pursuant sub-requirement
R1.12.
The drafting team addressed this directive by adding a new Requirement R5 to provide
the ERO with the information necessary to document and to make available for review to
users, owners, and operators of the Bulk-Power System, by request, a list of those
facilities that have protective relays set pursuant to Requirement R1, criterion 12.

•

P. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of entities
that receive the critical facilities list. [sub-requirement R3.3]

The drafting team addressed this directive by modifying Requirement R6, part 6.2
(formerly Requirement R3.3 in PRC-023-1), by adding the Regional Entity to the list of
entities that receive the list of circuits from the Planning Coordinator.
•

P. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.
The drafting team addressed this directive by adding Requirement R2, with an
appropriate violation risk factor and violation severity level, to require entities to set outof-step blocking elements to allow tripping of phase protective relays for faults that occur
during the loading conditions used to verify transmission line relay loadability per
Requirement R1. This new requirement replaces the requirement in Attachment A,
section 2 of PRC-023-1.

•

P. 264 . . . revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the Reliability
Standard.
The drafting team addressed this directive by revising Attachment A, section 1 to include
phase overcurrent supervisory elements (i.e., phase fault detectors) associated with
current-based, communication-assisted schemes (i.e., pilot wire, phase comparison, and
line current differential) where the scheme is capable of tripping for loss of
communications.

•

P. 283 . . . modify the Reliability Standard to include an implementation plan for sub-100
kV facilities.
The drafting team addressed this directive by including an implementation plan for sub100 kV facilities within the standard.

•

P. 284 . . . remove the exceptions footnote from the “Effective Dates” section.
The drafting team addressed this directive by removing of the exceptions footnote from
the “Effective Dates” section.

Test for Identifying Critical Facilities
The criteria in the proposed Reliability Standard PRC-023-2 Attachment B have been
added to address the directive to modify Requirement R3 of the Reliability Standard to include
the test that Planning Coordinators must use to identify sub-200 kV facilities that are critical to

the reliability of the bulk electric system. 13 These criteria also address the directive to apply an
“add in” approach to sub-100 kV facilities that are owned or operated by currently-Registered
Entities or entities that become Registered Entities in the future, and are associated with a facility
that is included on a critical facilities list defined by the Regional Entity. 14 NERC is in the
process of applying the test to a representative sample of utilities from each of the three
Interconnections and plans to file the results of these tests within the 24-month extension granted
in Order No. 733-A. 15 NERC plans to revise the applicability test defined in Attachment B, if
necessary, pending review of the results of this testing and the clarifications provided in Order
No. 733-A regarding the test for identifying critical facilities, and elements of the test such as
desirable system performance and base case descriptions. In the interim, NERC believes the
criteria in Attachment B of the proposed standard provide a significant step forward in
addressing the concerns noted in Order No. 733 and Order No. 733-A. Notably, by providing
criteria to be applied consistently by all Planning Coordinators, the test defined by these criteria
addresses the concern that any test to identify critical facilities must be consistent across regions
so that the effects of protective relay operation are consistent across regions. 16
In this proposed standard, the guidance provided by the NERC System Protection and
Control Task Force to the regions in 2005 has been refined to define a mandatory test to be
applied by Planning Coordinators to identify all circuits that must comply to achieve the
reliability objective of the standard. The methods included in the test are based on existing
criteria used to establish Flowgates that address circuit loading-based reliability concerns,
Interconnection Reliability Operating Limits (IROLs), and Nuclear Plant Interface Requirements
13

Order No. 733 at P 47.
Id. at P 60.
15
Transmission Relay Loadability Reliability Standard, 134 FERC ¶61,127 (February 17, 2011) (“Order No. 733A”) at P 78.
16
Order No. 733 at P 92.
14

(NPIRs), as well as criteria included in the Transmission Planning (TPL) standards. Using
existing methods associated with Flowgates, IROLs, and NPIRs, and by drawing upon studies
already required by other standards, PRC-023-2 promotes efficiency and consistency among the
assessments that Planning Coordinators are required to conduct.
Order No. 733 establishes a number of parameters for the applicability test, noting that
Planning Coordinators must use a process that is consistent across regions and robust enough to
identify all facilities that should be subject to the Reliability Standard. 17 The Order states that
the test must define expectations of desirable system performance and describe the steady state
and dynamic base cases that Planning Coordinators must use in their assessments. 18 The Order
provides additional guidance regarding the Commission’s concerns and provides an appropriate,
but not necessarily exclusive, outcome to address those concerns.
NERC agrees with the overall principles in the Order—first and foremost the need to
identify a test that is consistent across regions and robust enough to identify all facilities that
should be subject to the standard. In developing this test, NERC has focused on the reliability
objective of this standard: to ensure that the protective relay settings will not limit transmission
loadability; not interfere with system operators’ ability to take remedial action to protect system
reliability; and be set to reliably detect all fault conditions and protect the electrical network from
these faults. NERC believes that while the test developed in Attachment B of PRC-023-2 varies
in some areas from the guidance provided in Order No. 733, the test nonetheless identifies all
facilities that must be subject to the standard to achieve its reliability objective. The following
discussion describes these differences and explains how the test in the proposed PRC-023-2
standard is an equally effective and efficient approach to address the Commission’s concerns.

17
18

Id. at P 49.
Id. at P 80.

The facilities that must be subject to the standard are described differently in

various reports, Orders, and versions of the subject Reliability Standard. PRC-023-2 refers to
circuits for which Transmission Owners, Generator Owners, and Distribution Providers must
comply with Requirements R1 through R5, while PRC-023-1 refers to facilities critical to the
reliability of the Bulk Electric System. Recommendation 21A of the U.S. Canada Task Force
Report refers to operationally significant circuits. 19 During the standard development process, a
number of industry comments expressed concern with potential confusion regarding use of the
phrase “critical to the reliability of the bulk electric system” in the context of PRC-023-1 versus
other standards such as those addressing critical infrastructure. As noted in Order No. 733, if a
facility trips on relay loadability following an initiating event and contributes to undesirable
system performance similar to what occurred during the August 2003 blackout (e.g., cascading
outages and loss of load) in the same way that the loss of monitored flowgates and interfaces
contributed to the August 2003 blackout, the facility is operationally significant for the purposes
of Recommendation 21A, and therefore critical to the reliability of the bulk electric system for
the purposes of PRC-023-1. 20 Because the test defined in Attachment B is designed to identify
circuits that if tripped on relay loadability following an initiating event could contribute to
undesirable system performance similar to what occurred during the August 2003 blackout,
NERC believes that referring to these circuits as circuits for which Transmission Owners,
Generator Owners, and Distribution Providers must comply with Requirements R1 through R5
also conveys the same meaning and is an equally effective and efficient approach to referring to
the circuits identified through the Planning Coordinators’ assessments.
19

See, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and
Recommendations, U.S.-Canada Power System Outage Task Force, April 5, 2004.
20
Order No. 733-A at P 73.

During the standard development process, a number of industry comments also

identified concern and confusion with the references to sub-100 kV facilities “that Regional
Entities have identified as critical to the reliability of the Bulk Electric System.” NERC believes
the confusion, in part, is because at present very few such facilities have been identified by the
Regional Entities. In most regions, no such facilities have been identified. NERC notes that
references in the NERC Statement of Compliance Registry Criteria to elements “necessary to
provide for the reliable operation of the interconnected transmission grid” are substantially the
same as references in Order No. 743 to “facilities necessary for operating an interconnected
electric transmission network.” The proposed PRC-023-2 standard refers to transmission lines
operated below 100 kV and transformers with low voltage terminals connected below 100 kV
that are “part of the BES” to address industry concerns and to provide alignment with the
definition of Bulk Electric System presently under development. NERC believes that the sub100 kV circuits that Regional Entities may identify as critical facilities should be included in the
definition of the Bulk Electric System, and that referring to sub-100 kV circuits that are part of
the Bulk Electric System conveys the same meaning and is an equally effective and efficient
approach to referring to the circuits that Regional Entities have identified as critical to the
reliability of the Bulk Electric System.
3.

Order No. 733 provides guidance that the test must describe the steady state and

dynamic base cases that Planning Coordinators must use in their assessments. In developing the
test in Attachment B and aligning it with the reliability objective of the standard, NERC believes
it is sufficient to require power flow analysis based on steady-state base cases. Protective relays
tripped unnecessarily on August 14, 2003 as the result of two distinct phenomena: load
encroachment during steady-state conditions and unsecure operation during stable power swings.

The transmission lines that tripped unnecessarily on August 14 (i.e., excluding the lines that
tripped due to tree contact) up through tripping of the Argenta—Battle Creek and Argenta—
Tompkins 345 kV lines, tripped on load encroachment, whereas the subsequent transmission line
trips occurred due to power swings. While the power system did experience stable power swings
following each line trip up through tripping of the Argenta lines, these swings were not
significant in magnitude and were well-damped. Subsequent to each swing, the power system
returned to a new steady-state condition until the next line tripped on load encroachment. Thus,
power flow analysis using steady-state base cases is the appropriate study tool to assess the
potential for lines tripping under these conditions. A power flow simulation is adequate to assess
the post-contingency power flow state of the system. Transient stability analysis using dynamics
base cases is the appropriate study tool to assess lines tripping due to power swings that began
with tripping of the Thetford—Jewell and Hampton—Pontiac 345 kV lines. As directed in
Order No. 733 this phenomena will be addressed in a separate reliability standard. 21 Limiting
the applicability test in PRC-023-2 to power flow analysis with steady-state base cases and
addressing dynamics base cases in the separate standard addressing power swings is an equally
efficient and effective approach to address all aspects related to unnecessary tripping of
transmission lines due to relay loadability that occurred on August 14, 2003. As long as all
aspects of steady-state and dynamic base cases are addressed in Reliability Standards, it is
equally effective to limit PRC-023-2 to addressing steady-state concerns. Requiring assessment
of dynamic base cases in both PRC-023-2 and the separate standard addressing power swings is
less efficient, resulting in duplication of effort and diversion of limited resources from other
work.

Id. at P 150.

Order No. 733 provides guidance that the test must include the same system

simulations and assessments as the Transmission Planning (TPL) reliability standards for reliable
operation for all categories of contingencies used in transmission planning for all operating
conditions. In developing the test in Attachment B and aligning it with the reliability objective
of the standard, NERC believes it is sufficient to require more focused testing that exceeds the
TPL-003 Category C3 contingency. Because the TPL standards require the system to remain
stable with both thermal and voltage limits within applicable ratings, and prohibit loss of demand
and curtailment of firm transfers except demand directly served from the faulted facility, and
planned interruption of electric supply to customers or curtailment of firm transfers for events
resulting in loss of two or more elements, it is unnecessary to repeat this analysis within the test
defined in the proposed PRC-023-2 standard. Requiring that testing in PRC-023-2 will identify
circuits to which PRC-023-2 is applicable only in cases where entities are in violation of the TPL
standards. NERC believes it is more informative, and in line with the reliability objective, to
require testing of double contingency combinations without manual system adjustments in
between the two contingencies, thereby modeling a situation where a system operator may not
have time between the two contingencies to make appropriate system adjustments. That
situation reflects the events that led to the cascading outages due to transmission lines tripping on
load encroaching into the protective relay operating characteristic on August 14, 2003. For these
reasons, NERC believes this focused testing that exceeds the requirements of the TPL standards
is an equally effective and efficient approach to addressing the Commission’s concerns that the
test must be robust enough to identify all circuits that must comply to achieve the reliability
objective of the standard. While this approach requires analysis that exceeds that required in the
TPL standards, NERC expects that Planning Coordinators will use the same steady-state base

cases used to demonstrate compliance with the TPL standards in their assessments, thus
providing an efficient method of applying the test.
5.

Order No. 733 also provides guidance regarding the components of desirable

system performance that the test must seek to determine:
•

how continuity of all firm load supply should be maintained except for supply directly
served by the faulted facility;

•

the system should always be stable and within both thermal and voltage limits for reliable
operation;

•

and continuity of all firm transfers should be maintained.
NERC agrees that these components of desirable system performance are appropriate

when assessing the system simulations and assessments defined in the TPL standards. However,
in developing the test in Attachment B and aligning it with the reliability objective of the
standard, NERC believes it is most appropriate to focus on avoiding thermal loading of
transmission circuits that will challenge relays that are not set to provide adequate relay
loadability. If the loading of a transmission circuit exceeds its emergency rating above a
threshold that interferes with a system operator’s ability to take remedial action to protect system
reliability, then that circuit must comply with PRC-023-2 to achieve the reliability objective of
the standard. While the system performance measure in this test is less stringent than required
for Category C contingencies in TPL-003, it is important to note that the contingency itself is
more stringent than a Category C contingency, and the contingency and system performance
measure have been developed together, specifically for alignment with the reliability objective of
this standard. For this reason, NERC believes this test is an equally effective and efficient
approach to addressing the Commission’s concerns and results in a test that is robust enough to
identify all circuits that must comply to achieve the reliability objective of the standard.

Protective Relays Set Pursuant to Requirement R1, Criterion 2
Requirement R4 has been added to address the directive to modify PRC-023-1 to require
that transmission owners, generator owners, and distribution providers give their transmission
operators a list of transmission facilities that implement sub-requirement R1.2. 22 Providing this
information assures that Planning Coordinators, Transmission Operators, and Reliability
Coordinators are aware of situations in which a 15-minute rating has been used as the basis for
verifying transmission line relay loadability.
Protective Relays Set Pursuant to Requirement R1, Criterion 10
Requirement R1, criterion 10.1 has been added to address the directive to modify subrequirement R1.10 so that it requires entities to verify that the limiting piece of equipment is
capable of sustaining the anticipated overload for the longest clearing time associated with the
fault. 23 This additional requirement has been incorporated as a separate sub-requirement to
address confusion raised in stakeholder comments during the standard development process
regarding separation of requirements for “loadability” from requirements for “coordination with
the equipment capability.” The main requirement in criterion 10 is applicable to transformer
fault protection relays and transmission line relays on transmission lines terminated only with a
transformer, and requires that entities must set these relays to meet the loadability requirements.
The sub-requirement in criterion 10.1 addresses the issue of coordination with equipment
capability. Criterion 10.1 requires coordination so that load responsive transformer fault
protection relay settings do not expose transformers to a fault level and duration that exceeds the
transformer’s mechanical withstand capability. 24 NERC believes that stating the requirement in

Id. at P 186.
Id. at P 203.
24
IEEE C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause
4.4, Figure 4.
23

this manner is equally effective and efficient as the approach directed in Order No. 733, and
addresses concerns identified through the standard development process.
Order No. 733 explains that for the application of a transmission line terminated in a
transformer, protective relay settings implemented according to sub-requirement R1.10 would
allow the transformer to be subjected to overloads higher than its established ratings for
unspecified periods of time. The Commission states that this negatively impacts reliability and
raises safety concerns because transformers that have been subjected to currents over their
maximum rating have been recorded as failing violently, resulting in substantial fires. 25 Order
No. 733 explains further that applying protection systems that do not respect the actual or
verified capability of the limiting facility will result in a degradation of system reliability.
Failure of the transformer may not be limited to only the affected transformer, but may also
affect other Bulk-Power Systems elements in its vicinity, further degrading the reliability of the
Bulk-Power System. 26 Order No. 733-A also explains that the replacement due to a failure of
such a transformer could require a long lead-time, prolonging the Bulk-Power System’s return to
the level of reliability that preceded the failure. 27
During the standard development process, industry comments identified three main
concerns with modifying criterion 10 specifically as directed: (1) the need to define the throughfault capability by which this requirement is evaluated; (2) the need to define the longest clearing
time associated with the fault; and (3) availability of through-fault capability for every element in
series with the transformer. NERC believes it is necessary to address these concerns to provide
clear and measurable requirements to industry. To address these concerns NERC proposes an

Order 733 at P191.
Id, at P 210.
27
Order 733-A at P 120.
26

alternative solution that is an equally effective and efficient approach to addressing the
Commission’s reliability concerns and also addresses the industry’s concerns.
NERC agrees that a definitive measure is necessary for assessing the capability of
transformers to withstand through-fault currents. The relevant clause from the IEEE Guide for
Liquid-Immersed Transformer Through-Fault-Current Duration 28 has been cited in the proposed
PRC-023-2 standard to define this measure. The transformer damage curve has two components
for through-faults: the “thermal component” begins at two times the transformer nominal
nameplate rating, and the “mechanical component” begins at a current equal to the reciprocal of
twice the transformer impedance (e.g., five times the transformer nominal nameplate rating for a
transformer with 10 percent impedance). Industry comments correctly identified that for many
transformers, it is not possible to set fault protection relays to simultaneously meet the relay
loadability requirement established in criterion 10 and to coordinate with the thermal component
of the transformer damage curve. However, for through-fault magnitudes that exceed the
mechanical damage threshold, the mechanical withstand capability is more limiting than the
thermal withstand capability. For through-fault magnitudes below the mechanical damage
threshold, the permissible time duration to avoid thermal damage is measured in tens of seconds,
which is longer than the maximum expected through-fault duration for which a fault on the lowvoltage side of the transformer could remain before it is cleared by a protection system. 29 Thus,
requiring coordination of transformer fault protection relays with the mechanical withstand
capability of transformers assures that the transformers will be capable of withstanding the

IEEE C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause
4.4, Figure 4.
29
Order 733 at P 121 explains that the Commission’s use of the phrase “longest clearing time” is in the context of
the design and coordination of protection systems, where the “longest clearing time” refers to the longest time that a
fault could remain on the Bulk-Power System before it is cleared by a protection system.

anticipated overload for the longest clearing time associated with a fault on the low-voltage side
of the transformer.
Criterion 10.1 is limited to setting transformer fault protection relays to respect the
transformer through-fault capability without referencing the most limiting piece of equipment.
NERC believes that limiting criterion 10.1 to coordinating transformer fault protection relays
with the transformer mechanical withstand capability addresses the Commission’s concerns
regarding the potential for damage to transformers, potential damage to adjacent equipment if
transformers fail violently, and the prolonged time to return the system to the level of reliability
that preceded a failure due to the long lead-time required for replacement. Transformers, as a
result of physical design constraints, are more limiting than other series elements with regard to
through-fault capability when considering the expected duration for a fault on the low-voltage
side of the transformer. Detailed fault withstand capability of terminal equipment is not always
readily available (typically ratings are available only for momentary withstand capability and for
thermal loading associated with time constants much longer than the expected duration for a fault
on the low-voltage side of the transformer). Requiring entities to provide evidence that all
equipment in series with the transformer is capable of withstanding the through-fault current for
the expected duration for a fault on the low-voltage side of the transformer is not necessary to
address the Commission’s stated concerns, and places an unnecessary burden on entities without
a commensurate reliability benefit.
Protective Relays Set Pursuant to Requirement R1, Criterion 12
Requirement R5 addresses the directive to document, subject to audit by the Commission,
and to make available for review to users, owners, and operators of the Bulk-Power System, by
request, a list of those facilities that have protective relays set pursuant to sub-requirement

R1.12. 30 By requiring entities that set transmission line relays according to Requirement R1
criterion 12 to provide an updated list of the circuits associated with those relays to its Regional
Entity at least once each calendar year, NERC will have access to the information necessary to
maintain and make available for review a list of circuits with protective relays set pursuant to
Requirement R1, criterion 12.
List of Critical Facilities Provided by the Planning Coordinator
Requirement R6, part 6.2 (Requirement R3.3 in PRC-023-1) has been modified to
address the directive to add the Regional Entity to the list of entities that receive the critical
facilities list. 31 With this modification, the Planning Coordinators will be required to provide the
list of circuits identified through application of the criteria in Attachment B to all Regional
Entities, Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution
Providers within its Planning Coordinator area. Requirement R6, part 6.2 was also modified to
explicitly require providing the list to all of the listed entities to address concerns from some
Distribution Providers that may not have circuits on the list, to ensure they receive the list as
confirmation of this status.
Attachment A – Out-of-Step Blocking Schemes
Requirement R2 has been added to the standard to address the directive to include section
2 of Attachment A in the modified Reliability Standard as an additional Requirement with the
appropriate violation risk factor and violation severity level. 32 Within PRC-023-1 entities are
required to verify settings of out-of-step blocking schemes to ensure that they do not block
tripping for faults during the loading conditions defined within the requirements. This
requirement is stated in Attachment A, section 2 of PRC-023-1. This section of Attachment A
30

Order 733 at P 224.
Id. at P 237.
32
Id. at P 244.
31

has been deleted and replaced with the new Requirement R2. This new requirement has been
assigned a Violation Risk Factor and Violation Severity Level similar to Requirement R1, to
reflect the implicit link between Requirement R1 and Attachment A, section 2 in PRC-023-1 and
the similar impact to reliability of violating either requirement.
Attachment A – Protection Systems Excluded from the Reliability Standard
Attachment A, section 1.6 has been added to the standard, and Attachment A, section 3.1
(now section 2.1) has been revised to address the directives to remove the exclusion of
supervising relay elements in section 3.1 and to revise section 1 of Attachment A to include
supervising relay elements on the list of relays and protection systems that are specifically
subject to the Reliability Standard. 33 The new section 1.6 in Attachment A includes phase
overcurrent supervisory elements (i.e., phase fault detectors) associated with current-based,
communication-assisted schemes (i.e., pilot wire, phase comparison, and line current differential)
where the scheme is capable of tripping for loss of communications as subject to the
requirements in PRC-023-2. Section 2.1 (formerly section 3.1) has been modified to exclude
elements that are only enabled during a loss of communications, except as noted in section 1.6.
NERC believes that stating the requirement in section 1.6 in this manner is equally effective and
efficient as the approach directed in Order No. 733, and addresses concerns identified through
the standard development process.
Order No. 733 raised specific concerns about section 3.1, which excludes from the
Reliability Standard’s requirements relay elements that are enabled only when other relays or
associated systems fail, such as those overcurrent elements enabled only during loss of potential
conditions or elements enabled only during the loss of communications. The Commission
expressed concern that section 3.1 could be interpreted to exclude certain protection systems that
33

Id. at P 264.

use communications to compare current quantities and directions at both ends of a transmission
line, such as pilot wire protection or current differential protection systems supervised by fault
detector relays. The Commission explained that if supervising fault detector relays are not
subject to the Reliability Standard, and they are set below the rating of the protected element, the
loss of communications and heavy line loading conditions that approach the line rating would
cause them to operate and unnecessarily disconnect the line; adjacent transmission lines with
similar protection systems and settings would also operate unnecessarily, resulting in cascading
outages. 34
During the standard development process, industry comments identified concerns that
modifying Attachment A specifically as directed will have an unintended negative impact on
system reliability by impacting the dependability and security of certain protection systems.
Commenters expressed particular concern with applying relay loadability requirements to
overcurrent fault detectors applied to supervise phase distance (impedance) elements.
The elements described in section 1.6 are included explicitly to assure PRC-023-2
addresses the concerns stated in Order No. 733. The description is more specific than the
directive based on careful consideration of industry comments that identified the potential for
unintended, negative impacts on reliability that could occur with an overly broad description.
Phase overcurrent elements are often applied to supervise other protective functions for
which responsible entities already are required to meet the relay loadability requirements; e.g.,
phase distance. These overcurrent elements are utilized as “fault detectors” to allow the
supervised protective function to take action contingent on there being some level of fault current
present. These overcurrent elements inherently add an important security to the overall
protection system and help prevent undesired operation. In this application, the fault detectors
34

Id. at P 251.

by themselves cannot trip on load current, with or without time delay. Since the trip logic
requires assertion of the fault detector and the supervised protective function (which already is
required to meet the loadability requirements), the overall protective system function will meet
the loadability requirement. Requiring these supervisory elements to meet the requirements of
PRC-023-2 is unnecessary to achieve the reliability objective of the standard and in many cases
would have an unintended negative impact on reliability. Setting these fault detectors to meet the
requirements of PRC-023 would restrict the ability of some distance elements to trip for end-of-zone
faults, particularly on weak source systems, and would unnecessarily reduce the sensitivity of the
protection system, in many cases preventing the protection system from providing adequate
protection. Eliminating the fault detector to avoid this concern would have the negative impact of
making the protection system susceptible to undesired tripping such as during close-in faults on
adjacent elements, and in many cases microprocessor relays have inherent overcurrent supervision of
impedance elements which cannot be disabled. Placing an unnecessary requirement on fault
detectors in such cases would require unnecessary replacement of protection system equipment.
Fault detectors also are used to improve trip dependability in breaker failure protection
schemes. In this application also, the fault detectors by themselves cannot trip on load current, with
or without time delay. Because the breaker failure scheme is initiated only when a fault has been

detected by a protective relay, the overall protective function will meet the loadability
requirement. Requiring entities to set breaker failure fault detectors to meet the relay loadability
requirements would decrease sensitivity of the breaker failure scheme, and could result in a
failure to clear low-grade faults with current levels below the relay loadability requirement.
NERC believes that the concerns stated in Order No. 733 do not extend to fault detectors
used to increase protection system security or dependability as described above. By restricting
section 1.6 of Attachment A as proposed, an equally effective and efficient approach is used to

address the Commission’s concerns related to current-based communication-assisted schemes by
requiring entities to set supervisory elements to meet the relay loadability requirements in those cases
where the overcurrent element will trip directly for the loss of communication. This equally effective
and efficient approach avoids placing unnecessary requirements on other supervisory elements, with
potential negative impacts on overall system reliability.

Implementation Plan for Sub-100 kV Facilities
The Implementation Plan for PRC-023-2 includes Effective Dates for circuits operated
below 100 kV to address the directive to modify the Reliability Standard to include an
Implementation Plan for sub-100 kV facilities. 35 The Implementation Plan is the same for all
applicable circuits operated below 200 kV.
Effective Dates -- Footnote 1
Footnote 1 has been removed from the standard to address the directive to remove the
exceptions footnote from the “Effective Dates” section. 36 NERC notes that this modification has
no impact on entities that received temporary exceptions under the Beyond Zone 3 protection
system review program because all temporary exceptions have expired. The latest due date for
mitigation of temporary exceptions was December 31, 2008.

A Mapping Document was prepared by the drafting team for Project 2010-13 Relay
Loadability Order 733 to highlight and align the changes made to the PRC-023-1 standard
requirements that address the industry stakeholder comments and the Commission’s directives.
The mapping document summarizes the changes made to the PRC-023-1 standard in a
comprehensive, but streamlined manner and provides a record of the resulting changes to the

35
36

Id. at P 283.
Id. at P 284.

PRC-023-1 requirements in the PRC-023-2 standard. Exhibit D contains the PRC-023-2
mapping of requirements from PRC-023-1.
The proposed Reliability Standard set out in Exhibit A has been developed and approved
by industry stakeholders using NERC’s Reliability Standards Development Procedure and its
replacement, the NERC Standard Processes Manual. 37 A discussion of this process appears in
section III.c. of this filing. The proposed PRC-023-2 Reliability Standard was approved by the
NERC Board of Trustees on March 10, 2011.

IV. JUSTIFICATION FOR APPROVAL OF PROPOSED MODIFICATIONS TO
RELIABILITY STANDARDS
a. Section Overview
This section summarizes the development of the proposed PRC-023-2 Reliability
Standard. The discussion in this section is also intended to demonstrate that the proposed
modifications meet the criteria for approval established by FERC. That is, the modifications to
the proposed PRC-023-2 Reliability Standard ensure that they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. 38
The proposed PRC-023-2 Reliability Standard is provided in Exhibit A in both clean and
redlined format. The Implementation Plan for PRC-023-2 is provided in Exhibit B. The
standard drafting team roster for Project 2010-13 Relay Loadability Order 733, the drafting team
responsible for drafting the proposed Reliability Standard, is provided in Exhibit C. The
Mapping Document which highlights the revisions made to PRC-023-1 to address the
37

NERC’s Reliability Standards Development Procedure and its replacement the NERC Standard Processes
Manual are available on NERC’s website at
http://www.nerc.com/fileUploads/File/Standards/RSDP_V6_1_12Mar07.pdf. Note that FERC approved the new
Reliability Standard Processes Manual on September 3, 2010 (FERC Docket No. RR10-12-000), which replaces the
Reliability Standards Development Procedure Version 7 in its entirety.
38
See Order No. 672.

Commission’s Directives in Order 733 is provided in Exhibit D. The complete development
record for the proposed Reliability Standard and the associated Implementation Plan is provided
in Exhibit F. This extensive development record includes successive drafts of the standard, the
ballot pool members, the final ballot results by registered ballot body members, stakeholder
comments received during the development of proposed PRC-023-2 Reliability Standard, and a
discussion regarding how stakeholder comments were considered in developing the
modifications to the standard.
The proposed PRC-023-2 Reliability Standard contains 6 requirements:
•

Requirement R1 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider shall use any one of the identified criteria (Requirement R1,
criteria 1 through 13) for any specific circuit terminal to prevent its phase
protective relay settings from limiting transmission system loadability while
maintaining reliable protection of the BES for all fault conditions. Each
Transmission Owner, Generator Owner, and Distribution Provider shall evaluate
relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees.

•

Requirement R2 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider shall set its out-of-step blocking elements to allow tripping
of phase protective relays for faults that occur during the loading conditions used
to verify transmission line relay loadability per Requirement R1.

•

Requirement R3 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider that uses a circuit capability with the practical limitations
described in Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall use the calculated
circuit capability as the Facility Rating of the circuit and shall obtain the

agreement of the Planning Coordinator, Transmission Operator, and Reliability
Coordinator with the calculated circuit capability
•

Requirement R4 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis
for verifying transmission line relay loadability shall provide its Planning
Coordinator, Transmission Operator, and Reliability Coordinator with an updated
list of circuits associated with those transmission line relays at least once each
calendar year, with no more than 15 months between reports

•

Requirement R5 mandates that each Transmission Owner, Generator Owner, and
Distribution Provider that sets transmission line relays according to Requirement
R1 criterion 12 shall provide an updated list of the circuits associated with those
relays to its Regional Entity at least once each calendar year, with no more than
15 months between reports, to allow the ERO to compile a list of all circuits that
have protective relay settings that limit circuit capability

•

Requirement R6 mandates that each Planning Coordinator shall conduct an
assessment at least once each calendar year, with no more than 15 months
between assessments, by applying the criteria in Attachment B to determine the
circuits in its Planning Coordinator area for which Transmission Owners,
Generator Owners, and Distribution Providers must comply with Requirements
R1 through R5. The Planning Coordinator shall:
o Maintain a list of circuits subject to PRC-023-2 per application of
Attachment B, including identification of the first calendar year in which
any criterion in Attachment B applies.

o Provide the list of circuits to all Regional Entities, Reliability
Coordinators, Transmission Owners, Generator Owners, and Distribution
Providers within its Planning Coordinator area within 30 calendar days of
the establishment of the initial list and within 30 calendar days of any
changes to that list

a. Demonstration that the proposed Reliability Standard is just, reasonable, not
unduly discriminatory or preferential and in the public interest
In order to approve a Reliability Standard proposed by the ERO, FERC must determine,
after notice and opportunity for public hearing, that the standard is just, reasonable, not unduly
discriminatory or preferential and in the public interest. 39 In Order No. 672, FERC identified a
number of criteria it will use to analyze Reliability Standards proposed for approval to ensure
they are just, reasonable, not unduly discriminatory or preferential, and in the public interest. A
discussion of how the proposed PRC-023-2 Reliability Standard meets the guidelines identified
by FERC in Order No. 672 that FERC considers in approving a proposed standard follows.
1. Proposed Reliability Standards must be designed to achieve a specified reliability goal.
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern
that falls within the requirements of section 215 of the FPA. That is, it must provide for the
reliable operation of Bulk-Power System facilities. It may not extend beyond reliable operation
of such facilities or apply to other facilities. Such facilities include all those necessary for
operating an interconnected electric energy transmission network, or any portion of that
network, including control systems. The proposed Reliability Standard may apply to any design
of planned additions or modifications of such facilities that is necessary to provide for reliable
operation. It may also apply to Cyber security protection.
The proposed PRC-023-2 Reliability Standard is designed to achieve a specified
reliability goal by requiring that protective relay settings do not limit transmission loadability; do
not interfere with system operators’ ability to take remedial action to protect system reliability;
39

Section 215(d)(2)(A) of the FPA; 18 C.F.R. §39.5.

and are set to reliably detect all fault conditions and protect the electrical network from these
faults. The standard is applicable to a subset of the circuits necessary for operating the
interconnected transmission network; specifically, to circuits, that, if they trip due to relay
loadability following an initiating event, may contribute to undesirable system performance
similar to what occurred during the August 2003 blackout. This subset includes all circuits
operated at 200 kV and above, and circuits operated below 200 kV that are selected by the
Planning Coordinator by applying the criteria in Attachment B to determine the circuits in its
Planning Coordinator area for which Transmission Owners, Generator Owners, and Distribution
Providers must comply with the standard.
2. Proposed Reliability Standards must contain a technically sound method to achieve the
goal.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a
specified reliability goal and must contain a technically sound means to achieve this goal.
Although any person may propose a topic for a Reliability Standard to the ERO, in the ERO’s
process, the specific proposed Reliability Standard should be developed initially by persons
within the electric power industry and community with a high level of technical expertise and be
based on sound technical and engineering criteria. It should be based on actual data and
lessons learned from past operating incidents, where appropriate. The process for ERO
approval of a proposed Reliability Standard should be fair and open to all interested persons.
The proposed PRC-023-2 Reliability Standard establishes technically sound bases for
assuring that protective relay settings do not limit transmission loadability and do not interfere
with system operators’ ability to take remedial action to protect system reliability; and also to
assure that Planning Coordinators consistently apply a method that identifies all circuits that
potentially could, if they trip due to relay loadability following an initiating event, contribute to
undesirable system performance similar to what occurred during the August 2003 blackout.
The criteria established in Requirement R1 provide a sound, technical basis for assuring
relay loadability does not interfere with system reliability by requiring responsible entities to

validate their load-responsive phase protection settings against criteria specifically developed to
assure that operators have time to take remedial actions before circuits operating within their
capability are tripped by protection systems. Two criteria are based on thermal capability of
transmission circuits. When transmission system loadability is limited by criteria other than
thermal capability (e.g., transfer capability is limited by system stability or topology) a
responsible entity may use an alternate criterion, based on situation-specific details, to verify
relay loadability. Each of these criteria were developed by industry subject matter experts based
on experience with actual system disturbances and system operating experience, and based on
the protection system review programs developed following the August 2003 blackout. These
same criteria also form the basis for setting out-of-step blocking protection systems that could be
affected by the same operating conditions as load-responsive phase protection systems.
The criteria established in Requirement R6 and Attachment B provide a sound, technical
basis for assuring that Planning Coordinators identify all circuits for which a failure to assure
adequate relay loadability could result in cascading outages similar to what occurred during the
August 2003 blackout. The methods included in Attachment B are based on existing criteria
used to establish Flowgates that address circuit loading-based reliability concerns,
Interconnection Reliability Operating Limits (IROLs), and Nuclear Plant Interface Requirements
(NPIRs), as well as criteria included in the Transmission Planning (TPL) standards. The criteria
included in the TPL standards have been adapted to cover the specific reliability objective of this
standard to assure relay loadability when contingencies occur without time for operator
intervention between contingencies. Additional criteria also are included to address unique cases
that are not addressed in the criteria described above.
3. Proposed Reliability Standards must be applicable to users, owners, and operators of the
bulk power system, and not others.

Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any
user, owner, or operator of such facilities, but not on others.
The proposed PRC-023-2 Reliability Standard is applicable only to Transmission
Owners, Generator Owners, and Distribution Providers with load-responsive phase protection
systems as described in PRC-023-2 - Attachment A, applied to circuits operated at 200 kV and
above and applied to circuits operated below 200 kV as selected by the Planning Coordinator;
and to Planning Coordinators who are required to apply the criteria in Attachment B to determine
the circuits in its Planning Coordinator area for which Transmission Owners, Generator Owners,
and Distribution Providers must comply with the standard.
4. Proposed Reliability Standards must be clear and unambiguous as to what is required and
who is required to comply.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous
regarding what is required and who is required to comply. Users, owners, and operators of the
Bulk-Power System must know what they are required to do to maintain reliability.
Each of the requirements in the proposed PRC-023-2 Reliability Standard is clear in
identifying the required performance (what) and the responsible entity (who).
Requirement R1 requires each Transmission Owner, Generator Owner, and Distribution
Provider to prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the bulk electric system for all fault
conditions. The responsible entities are required to use any one of 13 criteria, for each specific
circuit terminal, to demonstrate that loadability requirements are met.
Requirement R2 requires each Transmission Owner, Generator Owner, and Distribution
Provider to set its out-of-step blocking elements to allow tripping of phase protective relays for
faults that occur during the loading conditions used to verify transmission line relay loadability
per Requirement R1.

Requirement R3 requires each Transmission Owner, Generator Owner, and Distribution
Provider that uses a circuit capability with the practical limitations described in Requirement R1,
criterion 6, 7, 8, 9, 12, or 13 to use the calculated circuit capability as the Facility Rating of the
circuit and to obtain the agreement of the Planning Coordinator, Transmission Operator, and
Reliability Coordinator with the calculated circuit capability.
Requirement R4 requires each Transmission Owner, Generator Owner, and Distribution
Provider that chooses to use Requirement R1 criterion 2 as the basis for verifying transmission
line relay loadability to provide its Planning Coordinator, Transmission Operator, and Reliability
Coordinator with an updated list of circuits associated with those transmission line relays at least
once each calendar year, with no more than 15 months between reports.
Requirement R5 requires each Transmission Owner, Generator Owner, and Distribution
Provider that sets transmission line relays according to Requirement R1 criterion 12 to provide
an updated list of the circuits associated with those relays to its Regional Entity at least once
each calendar year, with no more than 15 months between reports, to allow the ERO to compile a
list of all circuits that have protective relay settings that limit circuit capability.
Requirement R6 requires each Planning Coordinator to conduct an assessment at least
once each calendar year, with no more than 15 months between assessments, by applying the
criteria in Attachment B of PRC-023-2 to determine the circuits in its Planning Coordinator area
for which Transmission Owners, Generator Owners, and Distribution Providers must comply
with Requirements R1 through R5. The Planning Coordinator is required to maintain a list of
circuits subject to PRC-023-2 per application of Attachment B, including identification of the
first calendar year in which any criterion in Attachment B applies, and to provide the list of
circuits to all Regional Entities, Reliability Coordinators, Transmission Owners, Generator

Owners, and Distribution Providers within its Planning Coordinator area within 30 calendar days
of the establishment of the initial list and within 30 calendar days of any changes to that list.

5. Proposed Reliability Standards must include clear and understandable consequences and a
range of penalties (monetary and/or non-monetary) for a violation.
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for
violating a proposed Reliability Standard should be clear and understandable by those who must
comply.
The proposed standard includes clear and understandable consequences by assigning each
primary requirement a violation risk factor (“VRF”) and a violation severity level (“VSL”).
These elements support the determination of an initial value range for the Base Penalty Amount
regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
ERO Sanction Guidelines. The table below shows the VRFs and VSLs resulting in the indicated
range of penalties for violations.

Requirement R1
VRF
High

Lower
VSL
N/A

Moderate
VSL

High VSL

N/A

Severe VSL
The responsible entity did not use any
one of the following criteria
(Requirement R1 criterion 1 through
13) for any specific circuit terminal to
prevent its phase protective relay
settings from limiting transmission
system loadability while maintaining
reliable protection of the Bulk Electric
System for all fault conditions
OR
The responsible entity did not evaluate
relay loadability at 0.85 per unit voltage
and a power factor angle of 30 degrees

Requirement R2
VRF
High

Lower
VSL
N/A

Moderate
VSL

High VSL

N/A

Moderate
VSL

High VSL

N/A

Severe VSL
The responsible entity failed to ensure
that its out-of-step blocking elements
allowed tripping of phase protective
relays for faults that occur during the
loading conditions used to verify
transmission line relay loadability per
Requirement R1

Requirement R3
VRF
Medium

Lower
VSL
N/A

Severe VSL
The responsible entity that uses a
circuit capability with the practical
limitations described in Requirement
R1 criterion 6, 7, 8, 9, 12, or 13 did
not use the calculated circuit capability
as the Facility Rating of the circuit
OR
The responsible entity did not obtain
the agreement of the Planning
Coordinator, Transmission Operator,
and Reliability Coordinator with the
calculated circuit capability

Requirement R4
VRF
Lower

Lower
VSL
N/A

Moderate
VSL

High VSL

N/A

Severe VSL
The responsible entity did not provide
its Planning Coordinator,
Transmission Operator, and Reliability
Coordinator with an updated list of
circuits that have transmission line
relays set according to the criteria
established in Requirement R1
criterion 2 at least once each calendar
year, with no more than 15 months
between reports

Requirement R5
VRF
Lower

Lower
VSL
N/A

Moderate
VSL

High VSL

N/A

Severe VSL
The responsible entity did not provide
its Regional Entity, with an updated
list of circuits that have transmission
line relays set according to the criteria
established in Requirement R1 The
responsible entity did not provide its
Regional Entity, with an updated list
of circuits that have transmission line
relays set according to the criteria
established in Requirement R1
criterion 12 at least once each calendar
year, with no more than 15 months
between reports

Requirement R6
VRF
High

Lower
VSL
N/A

Moderate VSL

High VSL

OR
The Planning
Coordinator used the
criteria established
within Attachment B
at least once each
calendar year, with
no more than 15
months between

OR
The Planning
Coordinator
used the criteria
established
within

Severe VSL
The Planning
Coordinator failed to use
the criteria established
within Attachment B to
determine the circuits in
its Planning Coordinator
area for which applicable
entities must comply with
the standard
OR
The Planning
Coordinator used the
criteria established within
Attachment B, at least
once each calendar year,
with no more than 15
months between
assessments to determine
the circuits in its
Planning Coordinator
area for which applicable
entities must comply with
the standard but failed to
meet parts 6.1 and 6.2
OR

VRF

Lower
VSL

Moderate VSL

High VSL

assessments to
determine the
circuits in its
Planning
Coordinator area for
which applicable
entities must comply
with the standard
and met 6.1 and 6.2
but failed to include
the calendar year in
which any criterion
in Attachment B
first applies

Attachment B
at least once
each calendar
year, with no
more than 15
months between
assessments to
determine the
circuits in its
Planning
Coordinator
area for which
applicable
entities must
comply with the
standard and
met 6.1 and 6.2
but provided
the list of
circuits to the
Reliability
Coordinators,
Transmission
Owners,
Generator
Owners, and
Distribution
Providers
within its
Planning
Coordinator
area between 46
days and 60
days after list
was established
or updated.
(part 6.2)

OR
The Planning
Coordinator used the
criteria established
within Attachment B
at least once each
calendar year, with
no more than 15
months between
assessments to
determine the
circuits in its
Planning
Coordinator area for
which applicable
entities must comply
with the standard
and met 6.1 and 6.2
but provided the list
of circuits to the
Reliability
Coordinators,
Transmission
Owners, Generator
Owners, and
Distribution
Providers within its
Planning
Coordinator area
between 31 days and
45 days after the list
was established or
updated. (part 6.2)

Severe VSL
The Planning
Coordinator used the
criteria established within
Attachment B at least
once each calendar year,
with no more than 15
months between
assessments to determine
the circuits in its
Planning Coordinator
area for which applicable
entities must comply with
the standard but failed to
maintain the list of
circuits determined
according to the process
described in Requirement
R6. (part 6.1)
OR
The Planning
Coordinator used the
criteria established within
Attachment B at least
once each calendar year,
with no more than 15
months between
assessments to determine
the circuits in its
Planning Coordinator
area for which applicable
entities must comply with
the standard and met 6.1
but failed to provide the
list of circuits to the
Reliability Coordinators,
Transmission Owners,
Generator Owners, and
Distribution Providers
within its Planning
Coordinator area or
provided the list more
than 60 days after the list
was established or
updated. (part 6.2)
OR
The Planning
Coordinator failed to
determine the circuits in
its Planning Coordinator
area for which applicable
entities must comply with

VRF

Lower
VSL

Moderate VSL

High VSL

Severe VSL
the standard

6. Proposed Reliability Standards must identify clear and objective criterion or measure for
compliance, so that it can be enforced in a consistent and non-preferential manner.
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in
compliance with a proposed Reliability Standard. It should contain or be accompanied by an
objective measure of compliance so that it can be enforced and so that enforcement can be
applied in a consistent and non-preferential manner.
The proposed PRC-023-2 Reliability Standard identifies clear and objective criteria in the
language of the requirements so that the standards can be enforced in a consistent and nonpreferential manner. The language in the requirements is unambiguous with respect to the
applicable entity expectations. Each requirement has a single associated measure.
M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
evidence such as spreadsheets or summaries of calculations to show that each of its
transmission relays is set according to one of the criteria in Requirement R1,
criterion 1 through 13 and shall have evidence such as coordination curves or
summaries of calculations that show that relays set per criterion 10 do not expose
the transformer to fault levels and durations beyond those indicated in the standard.
(R1)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
evidence such as spreadsheets or summaries of calculations to show that each of its out-ofstep blocking elements is set to allow tripping of phase protective relays for faults that
occur during the loading conditions used to verify transmission line relay loadability per
Requirement R1. (R2)
M3. Each Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence
such as Facility Rating spreadsheets or Facility Rating database to show that it used the
calculated circuit capability as the Facility Rating of the circuit and evidence such as dated
correspondence that the resulting Facility Rating was agreed to by its associated Planning
Coordinator, Transmission Operator, and Reliability Coordinator. (R3)
M4. Each Transmission Owner, Generator Owner, or Distribution Provider that sets
transmission line relays according to Requirement R1, criterion 2 shall have evidence such
as dated correspondence to show that it provided its Planning Coordinator, Transmission
Operator, and Reliability Coordinator with an updated list of circuits associated with those
transmission line relays within the required timeframe. The updated list may either be a

full list, a list of incremental changes to the previous list, or a statement that there are no
changes to the previous list. (R4)
M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets
transmission line relays according to Requirement R1, criterion 12 shall have evidence such
as dated correspondence that it provided an updated list of the circuits associated with those
relays to its Regional Entity within the required timeframe. The updated list may either be
a full list, a list of incremental changes to the previous list, or a statement that there are no
changes to the previous list. (R5)
M6. Each Planning Coordinator shall have evidence such as power flow results, calculation
summaries, or study reports that it used the criteria established within Attachment B to
determine the circuits in its Planning Coordinator area for which applicable entities must
comply with the standard as described in Requirement R6. The Planning Coordinator shall
have a dated list of such circuits and shall have evidence such as dated correspondence that
it provided the list to the Regional Entities, Reliability Coordinators, Transmission Owners,
Generator Owners, and Distribution Providers within its Planning Coordinator area within
the required timeframe.

7. Proposed Reliability Standards should achieve a reliability goal effectively and efficiently,
but do not necessarily have to reflect “best practices” without regard to implementation
cost.
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect
the optimal method, or “best practice,” for achieving its reliability goal without regard to
implementation cost or historical regional infrastructure design. It should however achieve its
reliability goal effectively and efficiently.
The proposed PRC-023-2 Reliability Standard helps the industry achieve the stated goals
effectively and efficiently. The proposed standard requires Transmission Owners, Generator
Owners, and Distribution providers to verify relay loadability using methods that were developed
following the August 2003 blackout as part of the protection system review programs in response
to Recommendation 8a of NERC’s Final Report on the August 2003 Blackout 40 and
Recommendation 21a of the U.S.-Canada Power System Outage Task Force’s Final Report on
the Blackout. 41 Use of these methods within PRC-023-2 assures achieving the reliability goal of
this standard in an effective and efficient manner familiar to the responsible entities.

Technical Analysis of the August 14, 2003, Blackout: What Happened, Why, and What Did We Learn?, Report to
the NERC Board of Trustees by the NERC Steering Group, July 13, 2004.
41
Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations,
U.S.-Canada Power System Outage Task Force, April 2004.

The proposed Reliability Standard also requires Planning Coordinators to apply the
criteria established in Attachment B to identify all circuits for which a failure to assure adequate
relay loadability could result in cascading outages similar to what occurred during the August
2003 blackout. The methods included in Attachment B are based on existing criteria used to
establish Flowgates that address circuit loading-based reliability concerns, Interconnection
Reliability Operating Limits (IROLs), and Nuclear Plant Interface Requirements (NPIRs), as
well as criteria included in the Transmission Planning (TPL) standards. The criteria allow
Planning Coordinators to utilize studies necessary for demonstrating compliance with the
Transmission Planning (TPL) standards as a basis for the assessment required in PRC-023-2. By
using existing methods associated with Flowgates, IROLs, and NPIRs, and by drawing upon
studies already required by other standards, PRC-023-2 assures achieving the reliability goal of
this standard in an effective and efficient manner familiar to the Planning Coordinators.

8. Proposed Reliability Standards cannot be “lowest common denominator,” i.e., cannot
reflect a compromise that does not adequately protect bulk power system reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the
entity that must comply with the Reliability Standard and the cost to those entities of
implementing the proposed Reliability Standard. However, the ERO should not propose a
“lowest common denominator” Reliability Standard that would achieve less than excellence in
operating system reliability solely to protect against reasonable expenses for supporting this
vital national infrastructure. For example, a small owner or operator of the Bulk-Power System
must bear the cost of complying with each Reliability Standard that applies to it.
The proposed Reliability Standard PRC-023-2 does not aim at “lowest common
denominator.” This standard establishes relay loadability requirements that exceed the methods
used on an ad hoc basis within the industry prior to establishment of this standard, with due
consideration of the size of entities that must comply and the associated cost. The criteria
established in PRC-023-2 exceed the methods used prior to this standard by establishing
uniform methods for assessing relay loadability, and most significantly, by considering system

operation during stressed, but recoverable system conditions with voltage as low as 0.85 per
unit. This standard also extends requirements to out-of-step blocking systems in addition to
load-responsive phase protection systems.
The proposed Reliability Standard also does not aim at a “lowest common denominator”
with respect to identifying circuits for which responsible entities must comply with the
requirements in this standard. In the approved Reliability Standard PRC-023-1, Planning
Coordinators were provided the latitude to develop their own methods for identifying circuits
critical to the reliability objective of the standard. The criteria developed within Attachment B of
PRC-023-2 were developed based on established methods for assuring system reliability,
irrespective of the methods presently used by Planning Coordinators to demonstrate compliance
with PRC-023-1. Basing the criteria in Attachment B on established methods for establishing
Flowgates, Interconnection Reliability Operating Limits (IROLs), and Nuclear Plant Interface
Requirements (NPIRs) assures a system reliability basis for identifying circuits. Adapting
planning study methods from reliability standard TPL-003 to address the specific reliability
objective of this standard provides a high level of confidence that all circuits are identified that
could impact system reliability if relay loadability requirements are not met. Providing the
Planning Coordinator the latitude to include additional circuits based on other studies or
assessments, in consultation with the facility owner, allows Planning Coordinators to address
unique cases by including any other circuits for which Transmission Owners, Generator Owners,
and Distribution Providers must comply to assure the reliability objective of this standard is met.

9. Proposed Reliability Standards may consider costs to implement for smaller entities but not
at consequence of less than excellence in operating system reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the
entity that must comply with the Reliability Standard and the cost to those entities of

implementing the proposed Reliability Standard. However, the ERO should not propose a
“lowest common denominator” Reliability Standard that would achieve less than excellence in
operating system reliability solely to protect against reasonable expenses for supporting this
vital national infrastructure. For example, a small owner or operator of the Bulk-Power System
must bear the cost of complying with each Reliability Standard that applies to it.
The proposed PRC-023-2 Reliability Standard does not create any differentiation in
requirements based on size. All entities, small and large, are expected to comply with this
standard in the same manner. The proposed PRC-023-2 Reliability Standard allows an entity
sufficient time to budget, procure, and install equipment when necessary to become compliant.
Smaller entities will have proportionately fewer circuits to which the standard is applicable and
therefore will have proportionately smaller costs to comply with the standard. The proposed
standard was posted for public comment on three occasions during the development of the
standard. During these postings, no entities expressed concerns that the requirements would be
too costly for smaller entities to implement.

10. Proposed Reliability Standards must be designed to apply throughout North America to
the maximum extent achievable with a single Reliability Standard while not favoring one
area or approach.
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout
the interconnected North American Bulk-Power System to the maximum extent this is achievable
with a single Reliability Standard. The proposed Reliability Standard should not be based on a
single geographic or regional model but should take into account geographic variations in grid
characteristics, terrain, weather, and other such factors; it should also take into account
regional variations in the organizational and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional variations in
market design if these affect the proposed Reliability Standard.
The requirements in the proposed PRC-023-2 Reliability Standard apply throughout
North America, with no exceptions. The proposed PRC-023-2 Reliability Standard is a single
standard that will be universally applicable in the portions of the United States and Canada that
recognize NERC as the ERO. The proposed PRC-023-2 Reliability Standard has been written to

establish mandatory criteria that will be applied consistently by each Planning Coordinator to
determine the circuits in its Planning Coordinator area for which Transmission Owners,
Generator Owners, and Distribution Providers must comply with the standard. These criteria in
Attachment B of the standard assure that all Planning Coordinators will use comprehensive and
rigorous criteria that are consistent across regions to avoid vulnerability to similar problems that
resulted in the cascade during the August 2003 blackout and other system disturbances. A
review of disturbances in which relay loadability has been a causal or contributing factor confirm
this phenomenon is not influenced by geographic variations, regional variations in the
organizational and corporate structures of transmission owners and operators, variations in
generation fuel type and ownership patterns, or regional variations in market design.
Accordingly, the requirements for identifying circuits for which responsible entities must comply
with the standard, and the requirements assigned to the responsible entities, are applied
uniformly throughout North America, with no exceptions.

11. Proposed Reliability Standards should cause no undue negative effect on competition or
restriction of the grid.
Order No. 672 at P 332. As directed by section 215 of the FPA, the Commission itself will give
special attention to the effect of a proposed Reliability Standard on competition. The ERO should
attempt to develop a proposed Reliability Standard that has no undue negative effect on
competition. Among other possible considerations, a proposed Reliability Standard should not
unreasonably restrict available transmission capability on the Bulk-Power System beyond any
restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over
another.
The requirements in the proposed PRC-023-2 Reliability Standard should cause no undue
negative effect on competition or restriction of the grid because it helps to assure that protective
relay settings do not limit loadability of the transmission system and do not interfere with system
operation. Responsible entities are required to meet these objectives except in specific cases for

which meeting these objectives prevent setting protective relays to reliably detect faults. In these
cases the standard requires the responsible entity to use the calculated circuit capability as the
Facility Rating of the circuit and to obtain the agreement of the Planning Coordinator,
Transmission Operator, and Reliability Coordinator with the calculated circuit capability. In
such cases, obtaining agreement of the Planning Coordinator, Transmission Operator, and
Reliability Coordinator assures system reliability in a transparent manner that prevents undue
preference or advantage for one competitor over another. Additionally, the proposed PRC-023-2
Reliability Standard enhances the operation and reliability of the grid and does not constrain
competition or restrict transmission capability. The purpose of the proposed standard is to assure
that protective relay settings do not limit transmission loadability; do not interfere with system
operators’ ability to take remedial action to protect system reliability; and are set to reliably
detect all fault conditions and protect the electrical network from these faults.

12. The implementation time for the proposed Reliability Standards must be reasonable.
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and
reasonable, the Commission will consider also the timetable for implementation of the new
requirements, including how the proposal balances any urgency in the need to implement it
against the reasonableness of the time allowed for those who must comply to develop the
necessary procedures, software, facilities, staffing or other relevant capability.
The proposed Implementation Plan is reasonable (see Exhibit B). The Implementation
Plan does not allow an excessively long time period for entities to become fully compliant, but
allows sufficient time to transition to become compliant. The Implementation Plan recognizes
that in some jurisdictions requirements in approved standard PRC-023-1 are not yet effective and
provides allowances accordingly.
The Implementation Plan provides Planning Coordinators 18 months to apply the criteria
in Attachment B to determine the circuits in its Planning Coordinator area for which

Transmission Owners, Generator Owners, and Distribution Providers must comply with the
standard. The 18-month phase-in for compliance is intended to provide Planning Coordinators
sufficient time: (1) to perform an initial assessment of all Transmission lines operated at 100 kV
to 200 kV and transformers with low voltage terminals connected at 100 kV to 200 kV, and all
Transmission lines operated below 100 kV and transformers with low voltage terminals
connected below 100 kV that are part of the BES; and (2) to develop a list of circuits subject to
PRC-023-2 per application of Attachment B, including identification of the first calendar year in
which any criterion in Attachment B applies, and provide the list of circuits to all Regional
Entities, Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution
Providers within its Planning Coordinator area.
The Implementation Plan provides Transmission Owners, Generator Owners, and
Distribution Providers varying amounts of time to comply with new or modified requirements in
PRC-023-2 depending on the amount of effort required to become compliant. Where no
modifications have been made to the standard, entities are required to be compliant on the first
effective date to avoid any gap in reliability.
Transmission Owners, Generator Owners, and Distribution Providers are provided six
months to become compliant with new Requirements R4 and R5. The time provided reflects the
reporting nature of these requirements.
Transmission Owners, Generator Owners, and Distribution Providers are provided 12
months to become compliant with Requirement R1, criterion 10.1. The time provided reflects
that entities will be required to validate their transformer fault protective relays settings.
Transmission Owners, Generator Owners, and Distribution Providers are provided 24
months to become compliant with the standard for supervisory elements as described in

Attachment A, section 1.6 of the proposed standard. The time provided reflects that entities will
be required validate their supervisory element settings, and revise settings or replace protective
relay systems when the supervisory elements cannot be reset to comply with the relay loadability
requirements.
Transmission Owners, Generator Owners, and Distribution Providers are required to be
compliant on the first effective date of PRC-023-2 for their switch-on-to-fault schemes if PRC023-1 already is effective for switch-on-to-fault schemes when PRC-023-2 is approved.
Otherwise, the effective date will be the same as for PRC-023-1. This approach assures there is
no gap in reliability while also assuring that the length of time provided to become compliant in
PRC-023-1 is not reduced by approval of PRC-023-2.
Transmission Owners, Generator Owners, and Distribution Providers are provided 39
months to become compliant with the standard for circuits identified by the Planning
Coordinator by applying the criteria in Attachment B, or until first day of the first calendar year
in which any criterion in Attachment B applies if the Planning Coordinator identifies the circuit
in an assessment of a future year more than 39 months beyond the year in which the assessment
is conducted. The time provided reflects the idea that entities will be required validate their
protective relays settings, and revise settings or replace protective relay systems when the
protective relays cannot be reset to comply with the relay loadability requirements. The time
also takes into consideration the fact that a significant number of circuits may be identified by
the Planning Coordinator and allows time to budget, procure, and install any protection system
equipment modifications. The implementation plan is consistent with the time provided in PRC023-1 for circuits designated by the Planning Coordinator as critical to the reliability of the Bulk
Electric System.

13. The Reliability Standard development process must be open and fair.
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets
the legal standard of review, we will entertain comments about whether the ERO implemented its
Commission-approved Reliability Standard development process for the development of the
particular proposed Reliability Standard in a proper manner, especially whether the process was
open and fair. However, we caution that we will not be sympathetic to arguments by interested
parties that choose, for whatever reason, not to participate in the ERO’s Reliability Standard
development process if it is conducted in good faith in accordance with the procedures approved
by the Commission.
NERC develops Reliability Standards in accordance with Section 300 (Reliability
Standards Development) of its Rules of Procedure and the NERC Standard Processes Manual,
which is included in the NERC Rules of Procedure as Appendix 3A. In its ERO Certification
Order, FERC 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. 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 and a
vote of stakeholders and the NERC Board of Trustees is required to approve a Reliability
Standard for submission to FERC. The drafting team developed this standard by following the
Reliability Standards development process. In this case, the standard was publicly posted for
comment on two occasions in 2010. The standard drafting team considered comments from the
industry and revised the standard and implementation plan accordingly. Directed modifications
to the standard and the new applicability test (Attachment B) were posted for informal comment
in August 2010 and September 2010 respectively, and the entire revised standard PRC-023-2
was posted for formal comment in November 2010. The formal posting included a concurrent
initial ballot during the last 10 days of the 45-day posting. A successive ballot was conducted in
January 2011 and a final recirculation ballot in February 2011. A total of four drafts of the PRC-

023-2 standard were developed. The ballot achieved a weighted segment affirmative vote of
68.83% with a quorum of 87.35%.

14. Proposed Reliability Standards must balance with other vital public interests.
Order No. 672 at P 335. Finally, we understand that at times development of a proposed
Reliability Standard may require that a particular reliability goal must be balanced against
other vital public interests, such as environmental, social and other goals. We expect the ERO to
explain any such balancing in its application for approval of a proposed Reliability Standard.
The proposed PRC-023-2 Reliability Standard does not conflict with any vital public
interests. Compliance with this proposed PRC-023-2 Reliability Standard supports reliability of
the interconnected systems by assuring that protective relay settings do not limit transmission
loadability; do not interfere with system operators’ ability to take remedial action to protect
system reliability; and are set to reliably detect all fault conditions and protect the electrical
network from these faults. There are no vital public interests that conflict with this reliability
goal and so it was not necessary to balance the reliability goal of this standard against any other
vital public interests.

15. Proposed Reliability Standard must not conflict with prior FERC Rules or Orders.
Order No. 672 at P.444. a potential conflict between a Reliability Standard under development
and a Transmission Organization function, rule, order, tariff, rate schedule, or agreement
accepted, approved, or ordered by the Commission should be identified and addressed during
the ERO’s Reliability Standard Development Process.
The proposed PRC-023-2 Reliability Standard does not conflict with any other prior
FERC Rules or Orders and adequately addresses the directives identified in FERC Order No.
733.

16. Proposed Reliability Standards must consider any other relevant factors.
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and
reasonable, we will consider the following general factors, as well as other factors that are
appropriate for the particular Reliability Standard proposed.
Order No. 672 at P 337. In applying the legal standard to review of a proposed Reliability
Standard, the Commission will consider the general factors above. The ERO should explain in
its application for approval of a proposed Reliability Standard how well the proposal meets
these factors and explain how the Reliability Standard balances conflicting factors, if any. The
Commission may consider any other factors it deems appropriate for determining if the proposed
Reliability Standard is just and reasonable, not unduly discriminatory or preferential, and in the
public interest. The ERO applicant may, if it chooses, propose other such general factors in its
ERO application and may propose additional specific factors for consideration with a particular
proposed Reliability Standard.
No other factors for FERC’s consideration were identified in the development of the
proposed PRC-023-2 Reliability Standard.

b. Violation Risk Factor and Violation Severity Level Assignments
The proposed PRC-023-2 Reliability Standard includes VRF and VSL assignments. The
ranges of possible penalties for violations are based upon the applicable VRF and VSLs and will
be administered based on the Sanctions table and supporting penalty determination process
described in the FERC-approved NERC Sanction Guidelines, included as Appendix 4B to the
NERC Rules of Procedure. Each primary requirement is assigned a VRF and a VSL. These
elements support the determination of an initial value range for the Base Penalty Amount
regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
ERO Sanction Guidelines.
Assignment of Violation Risk Factors
The standard drafting team applied the following criteria when proposing VRFs for the
requirements in the proposed PRC-023-2 Reliability Standard.
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
52

system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would
not be expected to adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor and control the bulk electric system; or, a
requirement that is administrative in nature and a requirement in a planning time frame
that, if violated, would not, under the emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. A planning requirement that is administrative in nature. 42
The standard drafting team also considered consistency with the FERC Violation Risk
Factor Guidelines for setting VRFs: 43
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical
impact on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System: 44
42

These three levels of risk are defined by NERC and recognized by FERC in the Order on Violation Risk Factors,
119 FERC ¶61,145 at P9 (May 18, 2007) (“VRF Rehearing Order”), and the Order on Compliance Filing, 121
FERC ¶61,179 at Appendix A (November 16, 2007).
43
See, VRF Rehearing Order.

−
−
−
−
−
−
−
−
−
−
−
−

Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.

Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation
Risk Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor
Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One
Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser
risk reliability objective, the VRF assignment for such Requirements must not be watered
down to reflect the lower risk level associated with the less important objective of the
Reliability Standard.
The following discussion addresses how the standard drafting team considered FERC’s
VSL Guidelines 2 through 5. The team followed Guideline 4 (rather than Guideline 1) in
assigning VSLs because Guideline 4 directs assignment of VRFs based on the impact of a
specific requirement to the reliability of the system, whereas Guideline 1 identifies a list of topics

Id. at n. 15.

that encompass nearly all topics within NERC’s Reliability Standards and implies that these
requirements should be assigned a “High” VRF.
There are six requirements in the proposed PRC-023-2 Reliability Standard:
Requirement R1
VRF for PRC-023-2, Requirement R1: High


FERC’s Guideline 1 — This requirement is directly related to NERC
Recommendation 8a and US Canada Power System Outage Task Force
Recommendation 21a, and is developed explicitly to address those
recommendations. A High VRF is consistent with the role that relay
loadability played in contributing to the August 14, 2003 Northeast Blackout.



FERC’s Guideline 2 — Requirement R2 has a similar reliability objective and
is assigned a High VRF.



FERC’s Guideline 3 — Not applicable. There are no other NERC Reliability
Standards that address similar reliability goals.



FERC’s Guideline 4 — The proposed VRF is consistent with the NERC
definitions of VRFs because as described above, the requirement ensures that
load-responsive protective relays will not improperly operate during the
loading conditions described within the R1 criteria. This requirement if
violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures.



FERC’s Guideline 5 — The proposed requirement does not co-mingle more
than one obligation and therefore this guideline does not apply.

Requirement R2 –
VRF for PRC-023-2, Requirement R2: High


FERC’s Guideline 1 — Not applicable. Out-of-step blocking elements did not
prevent tripping of phase protective relays during the August 14, 2003
Northeast Blackout.



FERC’s Guideline 2 — Requirement R2 references Requirement R1 and both
requirements are assigned a “High” VRF.



FERC’s Guideline 3 — Not applicable. There are no other NERC Reliability
Standards that address similar reliability goals.



FERC’s Guideline 4 — The proposed VRF is consistent with the NERC
definitions of VRFs because as described above the requirement ensures that
out-of-step blocking elements allow tripping of phase protective relays for
faults that occur during the loading conditions used to verify transmission line

relay loadability per Requirement R1. This requirement is in the planning
time frame and if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk
electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal
condition.


FERC’s Guideline 5 — The proposed requirement does not co-mingle more
than one obligation and therefore this guideline does not apply.

Requirement R3 VRF for PRC-023-2, Requirement R3: Medium


FERC’s Guideline 1 — Not applicable. The criteria to which this requirement
is related did not exist at the time of the August 14, 2003 Northeast Blackout.



FERC’s Guideline 2 — Not applicable. There are no other requirements in
this standard that address similar reliability goals.



FERC’s Guideline 3 — Requirement R2 of FAC-009-1 states that the
Transmission Owner and Generator Owner shall each provide Facility Ratings
for its solely and jointly owned Facilities that are existing Facilities, new
Facilities, modifications to existing Facilities and re-ratings of existing
Facilities to its associated Reliability Coordinator(s), Planning Authority(ies),
Transmission Planner(s), and Transmission Operator(s) as scheduled by such
requesting entities. This data exchange requirement is assigned a Medium
VRF.



FERC’s Guideline 4 — Because the purpose of the requirement is to ensure
that entities have consistent Facility Ratings in order to operate the BES
effectively, this VRF is consistent with the NERC Definition of a Medium
VRF.



FERC’s Guideline 5 — The proposed requirement does not co-mingle more
than one obligation and therefore this guideline does not apply.

Requirement R4 VRF for PRC-023-2, Requirement R4: Lower


FERC’s Guideline 1 — Not applicable. The criterion to which this
requirement is related did not exist at the time of the August 14, 2003
Northeast Blackout.



FERC’s Guideline 2 — Requirement R5 has a similar reliability objective and
is assigned a Lower VRF.



FERC’s Guideline 3 — Requirement R3 of PRC-015-0 states that the
Transmission Owner, Generator Owner, and Distribution Provider that owns
56

an SPS shall provide documentation of SPS data and the results of studies that
show compliance of new or functionally modified SPSs with NERC
Reliability Standards and Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on request (within 30 calendar
days). This data exchange requirement is assigned a Lower VRF.


FERC’s Guideline 4 — Because the purpose of the requirement is to share
information with other entities through the exchange of a report the
requirement is considered administrative in nature and consistent with the
definition of a Lower VRF.



FERC’s Guideline 5 — The proposed requirement does not co-mingle more
than one obligation and therefore this guideline does not apply.

Requirement R5 VRF for PRC-023-2, Requirement R5: Lower


FERC’s Guideline 1 — Not applicable. The criterion to which this
requirement is related did not exist at the time of the August 14, 2003
Northeast Blackout.



FERC’s Guideline 2 — Requirement R4 has a similar reliability objective and
is also assigned a Lower VSL.



FERC’s Guideline 3 — Requirement R3 of PRC-015-0 states that the
Transmission Owner, Generator Owner, and Distribution Provider that owns
an SPS shall provide documentation of SPS data and the results of studies that
show compliance of new or functionally modified SPSs with NERC
Reliability Standards and Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on request (within 30 calendar
days). This data exchange requirement is assigned a Lower VRF.



FERC’s Guideline 4 — Because the purpose of the requirement is to share
information with other entities through the exchange of a report, the
requirement is considered administrative in nature and consistent with the
definition of a Lower VRF.



FERC’s Guideline 5 — The proposed requirement does not co-mingle more
than one obligation and therefore this guideline does not apply.

Requirement R6 VRF for PRC-023-2, Requirement R6: High


FERC’s Guideline 1 — A High VRF is consistent with the role that relay
loadability played in contributing to the August 14, 2003 Northeast Blackout.
The Blackout Report identifies examples of sub-200 kV transmission lines
tripping due to relay loadability issues, which resulted in cascading outages of
higher voltage transmission lines.



FERC’s Guideline 2 — Requirement R6 requires Planning Coordinators to
determine which sub-200 kV facilities are subject to Requirement R1 and R2.
Since the facilities identified by the Planning Coordinator pursuant to
Requirement R6 are required to meet Requirement R1 and R2, the reliability
risk to the bulk power system of a violation of Requirement R6 is the same as
a violation of Requirement R1 or R2. Assigning a High VRF to Requirement
R6 is consistent with the VRFs assigned to Requirements R1 and R2.



FERC’s Guideline 3 — Not applicable. There are no other standards that
address similar reliability goals.



FERC’s Guideline 4 — The proposed VRF is consistent with the NERC
definitions of VRFs because, as described above, the requirement ensures that
the Planning Coordinator will evaluate sub-200 kV circuits to determine
which such circuits could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk
electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal
condition. Circuits thus identified will be subject to the other requirements of
PRC-023-2.



FERC’s Guideline 5 — The VRF is consistent with the highest risk reliability
objective contained in this requirement.

Violation Severity Levels
The VSLs are presented below, followed by an analysis of whether the VSLs meet the
FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes
that may encourage a lower level of compliance than was required when Levels of Noncompliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement

VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that
assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
Requirement R1
Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

The responsible entity did not use any one of the following criteria
(Requirement R1 criterion 1 through 13) for any specific circuit terminal to
prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the Bulk Electric System
for all fault conditions.
OR
The responsible entity did not evaluate relay loadability at 0.85 per unit
voltage and a power factor angle of 30 degrees

FERC VSL G1 Discussion

The proposed VSL for Requirement is consistent with the approved VSL for
the similar Requirement R1 within PRC-023-1.

FERC VSL G2 Discussion

Guideline 2a:
The proposed VSL is binary and assigns a “Severe” category for the
violation of the requirement.
Guideline 2b:
The proposed VSL for Requirement R2 does not contain ambiguous
language

FERC VSL G3 Discussion

The proposed VSL is consistent with the corresponding Requirement, R1.

FERC VSL G4 Discussion

The proposed VSL is based on a single violation and not a cumulative
number of violations.

Requirement R2
Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

The responsible entity failed to ensure that its out-of-step blocking elements
allowed tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per
Requirement R1.

FERC VSL G1 Discussion

The proposed VSL for Requirement R2 does not lower the current level of
compliance regarding out of step blocking elements. Out-of-step blocking
elements are addressed in Requirement R1 in PRC-023-1. Out-of-step
blocking has been included in a separate requirement in PRC-023-2 per
Order 733 and the VSLs for Requirements R1 and R2 are consistent.

FERC VSL G2 Discussion

FERC VSL G3 Discussion

The proposed VSL is consistent with the corresponding Requirement, R2.

FERC VSL G4 Discussion

The proposed VSL is based on a single violation and not a cumulative
number of violations.

Requirement R3
Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

The responsible entity that uses a circuit capability with the practical
limitations described in Requirement R1 criterion 6, 7, 8, 9, 12, or 13 did not
use the calculated circuit capability as the Facility Rating of the circuit.
OR
The responsible entity did not obtain the agreement of the Planning
Coordinator, Transmission Operator, and Reliability Coordinator with the
calculated circuit capability.

FERC VSL G1 Discussion

This VSL is consistent with the VSL assigned to Requirement R2 of
approved PRC-023-1, which is essentially identical and is replaced by this
requirement.

FERC VSL G2 Discussion

Guideline 2a:
The VSL is binary and establishes a severe level.
Guideline 2b:
The proposed VSL for Requirement R3 does not contain ambiguous
language.

FERC VSL G3 Discussion

The proposed VSL is consistent with the corresponding Requirement R3.

FERC VSL G4 Discussion

The proposed VSL is based on a single violation and not a cumulative

number of violations.

Requirement R4
Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

The responsible entity did not provide its Planning Coordinator,
Transmission Operator, and Reliability Coordinator with an updated list of
circuits that have transmission line relays set according to the criteria
established in Requirement R1 criterion 2 at least once each calendar year,
with no more than 15 months between reports.

FERC VSL G1 Discussion

This VLS does not lower the current level of compliance because this is a
new Requirement that did not exist in PRC-023-1.

FERC VSL G2 Discussion

Guideline 2a:
The VSL is binary and establishes a severe level.
Guideline 2b:
The proposed VSL for Requirement R4 does not contain ambiguous
language.

FERC VSL G3 Discussion

The proposed VSL is consistent with the corresponding Requirement R4.

FERC VSL G4 Discussion

The proposed VSL is based on a single violation and not a cumulative
number of violations.

Requirement R5
Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

The responsible entity did not provide its Regional Entity, with an updated
list of circuits that have transmission line relays set according to the criteria
established in Requirement R1 criterion 12 at least once each calendar year,
with no more than 15 months between reports.

FERC VSL G1 Discussion

The proposed VSL for Requirement R5 does not have the unintended
consequence of lowering the current level of compliance because PRC-023-1
does not have this requirement as it was added to PRC-023-2.

FERC VSL G2 Discussion

Guideline 2a:
The proposed VSL is binary and was assigned a severe VSL.
Guideline 2b:
The proposed VSL for Requirement R5 does not contain ambiguous
language.

FERC VSL G3 Discussion

The proposed VSL is consistent with the corresponding Requirement R5.

FERC VSL G4 Discussion

The proposed VSL is based on a single violation and not a cumulative
number of violations.

Requirement R6
Proposed Lower VSL

N/A

Proposed Moderate VSL

The Planning Coordinator used the criteria established within Attachment B
to determine the circuits in its Planning Coordinator area for which
applicable entities must comply with the standard and met parts 6.1 and 6.2,
but more than 15 months and less than 24 months lapsed between
assessments.
OR
The Planning Coordinator used the criteria established within Attachment B
at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard and met 6.1 and 6.2
but failed to include the calendar year in which any criterion in Attachment
B first applies.
OR
The Planning Coordinator used the criteria established within Attachment B
at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard and met 6.1 and 6.2
but provided the list of circuits to the Reliability Coordinators, Transmission
Owners, Generator Owners, and Distribution Providers within its Planning
Coordinator area between 31 days and 45 days after the list was established
or updated. (part 6.2)

Proposed High VSL

Proposed Severe VSL

The Planning Coordinator failed to use the criteria established within
Attachment B to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard.
OR
The Planning Coordinator used the criteria established within Attachment B,
at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard but failed to meet
parts 6.1 and 6.2.
OR

The proposed VSL for Requirement R6 does not have the unintended
consequence of lowering the current level of compliance.
The currently approved VSL for Requirement R3 of PRC-023-1 is binary
with only a Severe VSL assigned. However, the structure of Requirement
R6 is very different from the requirement it replaced (R3 in PRC-023-1) and
the new structure does allow for partial compliance. In its June 19, 2008
VSL Order, FERC indicated a preference for using graduated VSLs
wherever practical. In this instance, when comparing noncompliance with
PRC-023-1 Requirement R3 and noncompliance with PRC-023-2
Requirement R6, both sets of VSLs assign a Severe VSL for failure to
perform the study. Thus, the graduated VSL for Requirement R6 does not
have the unintended consequence of lowering the current level of
compliance.

FERC VSL G2 Discussion

Guideline 2a:
N/A
Guideline 2b:
The proposed VSL for Requirement R6 does not contain ambiguous
language

FERC VSL G3 Discussion

The proposed VSL is consistent with the corresponding Requirement R6.

FERC VSL G4 Discussion

The proposed VSL is based on a single violation and not a cumulative
number of violations.

REQUEST FOR FERC APPROVAL OF PROPOSED NERC RULES OF
PROCEDURE SECTION 1700—CHALLENGES TO DETERMINATIONS
The Commission directed in Order No. 733 NERC to develop a mechanism that would

allow entities to challenge criticality determinations made by the Planning Coordinators in
compliance with the proposed PRC-023-2 Reliability Standard. Paragraph 97 of Order No. 733
states:
97. Finally commenters argue that there should be some mechanism for entities
to challenge criticality determinations. We agree that such a mechanism is
appropriate and direct the ERO to develop an appeals process (or point to a
process in its existing procedures) and submit it to the Commission no later than
one year after the date of this Final Rule.
In response to this directive, NERC staff developed the proposed NERC Rules of
Procedure Section 1700—Challenges to Determinations, included at Exhibit E to this filing.
Under the proposed Section 1700, a registered entity with concerns about a determination by a
Planning Coordinator regarding the circuits in its Planning Coordinator area for which registered
entities must comply with the PRC-023-2 standard, would first work with the Planning
Coordinator directly. If the matter cannot be resolved there, the registered entity may ask the
appropriate Regional Entity to decide the matter. An entity not satisfied with the Regional Entity
decision may appeal to NERC. Review at the NERC level would be handled by a panel
appointed by the NERC Board of Trustees for that purpose. The NERC Board of Trustees would
have the discretion, but not the obligation, to review the matter further upon request. Upon the
final NERC Board of Trustees’ decision on the matter, a registered entity may seek ERO
governmental authority review of the NERC decision.
The proposed Section 1700—Challenges to Determinations was posted for a forty-five
day comment period, from January 21, 2011 to March 7, 2011. Nine parties provided comments
in response to the proposed changes. 45 Proposed Section 1700 was widely supported by all those
who commented.

The full set of comments received on the proposed Section 1700 is available at:
http://www.nerc.com/page.php?cid=1|8|169.

Comments received were generally focused on the following points:
•

Several commenters requested more clarity regarding the intent of Section 1700. One
commenter specifically pointed out that the scope of authority in Section 1701 was
vague, and NERC should state that Section 1701 governs appeals under the PRC-023
Reliability Standard. Other commenters requested that Section 1700 not be limited to
situations presented solely by the PRC-023 Reliability Standard.

•

One commenter proposed revising Section 1702.1 to more closely match the language
in FERC’s Order No. 733 directive for facilities that “are critical to the reliability of
the bulk power system” rather than the proposed Section 1702.1 language which
provides for “circuits in [the] Planning Coordinator Area for which Registered
Entities must comply with the standard.”

•

Several commenters suggested modifying the proposed Section 1700 to more clearly
define and formalize the timeframes for every step of the appeal process for
expediency and monitoring purposes. One commenter suggested that the opportunity
to appeal not be left open-ended and proposed that a 60-day window from the date of
notification to file an appeal. Another commenter suggested setting the deadlines for
submitting requests to the NERC Board of Trustees and to applicable governmental
authorities to 30 days each. Another commenter requested a definite time period by
which the Board of Trustees must: (i) decline to review the decision of the panel; and
(ii) issue a determination (if it wishes to do so) on appeal.

•

Two commenters suggested that the proposed rule should include a statement of the
standard of review that should be applied in making decisions on challenges.

•

One commenter requested that a list of criteria similar to that included in Section
1702.6 regarding the make-up of the appeal panel at the NERC Board of Trustee level
be added to paragraph 1702.4 regarding the make-up of the appeal panel at the
Regional Entity level.

•

Several commenters requested clarification on the compliance expectations during the
challenge process, and suggestions were made to suspend compliance obligations
while the appeals process is ongoing.

•

One commenter suggested limiting the authority granted in Section 1702.5 to appeal
decisions to only affected Registered Entities, rather than “any entity.”

•

Two commenters proposed adding additional procedures to require Planning
Coordinators to establish their own formal processes for receiving challenges to
determinations. One commenter suggested that these provisions would also clarify
which Planning Coordinator personnel should be provided with the notice of a
challenge from a Registered Entity.

In response to comments received, NERC made the following changes to the proposed
Section 1700:
•

Section 1702.1 was modified to more closely track the language in the PRC-023
standard to specify that a challenge of a Planning Coordinator’s determination will
apply to sub-200kV circuits in its Planning Coordinator area for which Transmission
Owners, Generator Owners, and Distribution Providers must comply with PRC-023.

•

Section 1702.2 was added to include more clarity on procedures the Planning
Coordinator must follow. This includes establishing a procedure for a Registered
Entity to submit a written request for an explanation of a determination made by the
Planning Coordinator, timelines for submitting such a request, and a timeline for
responding to such a request.

•

Section 1702.3 was modified to provide more clarity on the elements required to
support a Registered Entity’s challenge of a Planning Coordinator’s determination.

•

Section 1702.4 was added to state that a challenge filed in good faith would suspend
the time period for compliance with the PRC-023 standard for the particular facility
involved until the challenge is withdrawn, settled, or resolved.

•

Section 1702.5 was modified to provide more clarity regarding what is required in the
Regional Entity’s decision on the challenge by a Registered Entity. Section 1702.5
also includes the standard of review: The Regional Entity should affirm the
determination of the Planning Coordinator if it is supported by substantial evidence.

•

Section 1702.6 was modified to state that a Regional Entities, Registered Entity, or
Planning Coordinator may file a response to an appeal within 30 days of the appeal.

•

Section 1702.7 was modified to provide more clarity to the scope of the panel that the
Board of Trustees appoints to hear appeals from Regional Entity decisions regarding
PRC-023. A time period of 90 days for the panel to issue its decision was also added
to this section.

•

Section 1702.8 was modified to clarify the process that the Board of Trustees will use
in reviewing decisions issued by the panel appointed by the board. Importantly,
review by the Board of Trustees is at the Board’s discretion. The process includes
three options: (a) issuing a decision on the merits, which shall be the final NERC
decision; (b) issuing a notice declining to review the decision of the panel, in which
case the panel’s decision shall be the final NERC decision; or (3) if no written
decision or notice declining review is issued within 90 days, the appeal shall have
been deemed denied by the board.

•

Section 1702.9 was modified to provide that a Registered Entity or Planning
Coordinator may appeal the final NERC decision to the applicable governmental
authority within 30 days of the decision.

•

Section 1702.10 was modified to encourage the Planning Coordinators and
Registered Entity to resolve any disputes using alternative dispute resolution
procedures.

Additionally, one commenter suggested that a Regional Entity should be required to
make use of the formal hearing procedures from the Compliance Monitoring and Enforcement
Program for deciding all challenges under the proposed PRC-023-2 standard. NERC did not
implement that change, because NERC determined that the nature of the decision does not
warrant those formal procedures.

VI.

SUMMARY OF THE RELIABILITY STANDARD DEVELOPMENT
PROCEEDINGS
a. Development History
The proposed PRC-023-2 standard incorporates the first phase of the changes to PRC-

023-1 that were directed by the Commission in Order No. 733, which focuses on Transmission
Relay Loadability. The standard drafting team posted the draft PRC-023-2 Reliability Standard
for 3 public comment periods, including one informal comment period, one formal comment
period, and one Successive Ballot and comment period. Additionally, the standard drafting team
informally posted and requested comments on Attachment B to the proposed PRC-023 standard.
The initial draft of the standard was posted for a 30-day informal comment period from
August 19, 2010 to September 19, 2010. The proposed PRC-023-2 standard includes an
“applicability test” that was established by a Blue Ribbon Panel of industry experts formed by
NERC for use by Planning Coordinators to determine whether a sub-200 kV facility must
comply with PRC-023-2. The applicability test (Attachment B of the standard) was separately

posted for an abbreviated 20-day informal comment period from September 23, 2010 to October
12, 2010.
The PRC-023-2 standard including the Attachment B applicability test was posted for a
formal 45-day comment period with a 10-day concurrent ballot period from November 1, 2010
through December 16, 2010. A Ballot Pool was formed during the first 30 days of the comment
period, and a concurrent initial ballot period was open during the last 10-days of the comment
period, from December 7, 2010 through December 16, 2010. The drafting team received 38 sets
of comments, including comments from more than 67 different people from approximately 73
companies representing 9 of the 10 Industry Segments. Based on the comments received, the
changes made to the standard primarily clarified the obligations assigned to the entities and did
not substantively change the requirements. The significant comments received were focused on
the following areas of the standard:
•

Applicability: Modified to separately address the circuits for which Transmission
Owners, Generator Owners, and Distribution Providers must comply with
Requirements R1 through R5 versus the circuits to which the Planning
Coordinator must apply the criteria in Attachment B per Requirement R6

•

Effective Dates: The effective dates were modified to address the timeframe in
which Facility owners must comply with Requirements R1 through R5 when the
Planning Coordinator identifies a circuit for which the Facility owner must
comply with the standard

•

Requirement R1: Modified to provide additional clarity to ensure that protection
settings do not expose transformers to fault level and duration that exceed their
mechanical withstand capability.

•

Requirement R5: Registered Entities that set transmission line relays according to
Requirement R1 criterion 12 are required to provide a list of the circuits
associated with those relays to the Regional Entity at least once each calendar
year, with no more than 15 months between reports. The drafting team modified
the requirement to allow that an updated list of the circuits associated with those
relays be provided. The drafting team also added clarification within the
requirement that the purpose is to allow the ERO to compile a list of all circuits
that have protective relay settings that limit circuit capability.

•

Requirement R6: This requirement was modified to avoid redundancy with other
sections of this standard and to improve the clarity of the requirement. References
made to the Statement of Compliance Registry were replaced with the phrase
“that are included on a critical facilities list defined by the Regional Entity.”

•

Requirement R7: Deleted to remove the double jeopardy concern between
Requirements R1 through R5 and Requirement R7.

•

Attachment B (Applicability Test): Significant modifications were made to
Attachment B to help clarify the purpose and understanding of the requirements
of this standard and the applicability of the criteria identified in Attachment B.

A 20-day successive ballot and non-binding poll was conducted on the proposed PRC023-2 standard and VRF/VSLs, respectively, from January 24, 2011 to February 14, 2011. The
successive ballot achieved a quorum of 83.95% and a weighted segment approval of 65.71%.
For the non-binding poll on the VRF/VSLs, 80.0% of those registered provided an opinion, and
65% of those who provided an opinion indicated support for the VRFs and VSLs that were
proposed. The drafting team revised the text of the standard and the VRF/VSLs to account for
industry input and the formal comments received, and formally responded to each of the
stakeholder comments.
The significant comments received that resulted in modifications to the standard were
focused on the following areas:
•

Applicability: The references to circuits operated below 100 kV “that are included
on a critical facilities list defined by the Regional Entity” were revised to address
industry concerns. The drafting team modified this reference in the standard to
circuits operated below 100 kV that are “part of the BES” to provide additional
clarification and alignment with the definition of Bulk Electric System (BES)
presently under development.

•

Effective Dates: The presentation of effective dates was revised from a narrative
description to a tabular format to make the dates easier to comprehend.
Commenters had expressed confusion with the five different effective dates, and
their relationship with effective dates in PRC-023-1 and the timing of Planning
Coordinator assessments.

•

Attachment A: Section 1.6 was revised by inserting parenthetical statements to
clarify that the phrase “phase overcurrent supervisory elements” refers to phase
fault detectors and “current-based communication-assisted schemes” refers to
pilot wire, phase comparison, and line current differential schemes.

•

Measures: M4 and M5 were modified to clarify that attestations are acceptable
forms of evidence in years when there are no changes to the applicable lists of
circuits.

•

Violation Severity Levels: A VSL was added for Requirement R6 to cover the
situation where an entity is totally noncompliant with the requirement

The PRC-023-2 Reliability Standard was posted for a 10-day Recirculation Ballot from
February 24, 2011 to March 7, 2011, and an industry webinar was held on March 2, 2011 to
provide the industry with an opportunity to ask questions and better understand the issues and
concerns being addressed and the reasoning behind the revisions made to the standard.
Reliability Standard PRC-023-2 passed the recirculation ballot with a weighted affirmative vote
of 68.83% and a quorum of 87.35%.

VII.

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

proposed PRC-023-2 Reliability Standard included in Exhibit A, and the associated
Implementation Plan included in Exhibit B to this filing in accordance with Section 215(d)(1) of
the FPA and Part 39.5 of FERC’s regulations. NERC requests that these approvals be made
effective in accordance with the effective date provisions set forth in the proposed PRC-023-2
Reliability Standard. Additionally, NERC requests approval of the proposed Section 1700—
Challenges to Determinations, included as Exhibit E, to be added to the NERC Rules of
Procedure.

Respectfully submitted,
Gerald W. Cauley
President and Chief Executive Officer
David N. Cook
Senior Vice President and General Counsel
North American Electric Reliability Corporation
116-390 Village Boulevard
Princeton, NJ 08540-5721
(609) 452-8060
(609) 452-9550 – facsimile
david.cook@nerc.net

/s/ Holly A. Hawkins
Holly A. Hawkins
Assistant General Counsel for Standards
and Critical Infrastructure Protection
North American Electric Reliability
Corporation
1120 G Street, N.W.
Suite 990
Washington, D.C. 20005-3801
(202) 393-3998
(202) 393-3955 – facsimile
holly.hawkins@nerc.net

CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all parties
listed on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C. this 18th day of March, 2011.
/s/ Holly A. Hawkins
Holly A. Hawkins
Attorney for North American
Reliability Corporation

Electric

Exhibit A
Proposed PRC-023-2 Reliability Standard submitted for approval (Clean and Redline)

Standard PRC-023-2 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-2

3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with
system operators’ ability to take remedial action to protect system reliability and; be set to
reliably detect all fault conditions and protect the electrical network from these faults.
4. Applicability
4.1. Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.2 Generator Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.3 Distribution Providers with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1(Circuits Subject to
Requirements R1 – R5), provided those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinators
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator in accordance with R6.
4.2.1.3 Transmission lines operated below 100 kV that are part of the BES and
selected by the Planning Coordinator in accordance with R6.
4.2.1.4 Transformers with low voltage terminals connected at 200 kV and above.
4.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV
selected by the Planning Coordinator in accordance with R6.
4.2.1.6 Transformers with low voltage terminals connected below 100 kV that are part
of the BES and selected by the Planning Coordinator in accordance with R6.
4.2.2 Circuits Subject to Requirement R6
4.2.2.1 Transmission lines operated at 100 kV to 200 kV and transformers with low
voltage terminals connected at 100 kV to 200 kV
4.2.2.2 Transmission lines operated below100 kV and transformers with low voltage
terminals connected below 100 kV that are part of the BES

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
5.

Effective Dates

The effective dates of the requirements in the PRC-023-2 standard corresponding to the applicable
Functional Entities and circuits are summarized in the following table:

Effective Date
Requirement

Applicability

Each Transmission Owner, Generator
Owner, and Distribution Provider with
transmission lines operating at 200 kV and
above and transformers with low voltage
terminals connected at 200 kV and above,
except as noted below.
• For Requirement R1, criterion 10.1, to
set transformer fault protection relays
on transmission lines terminated only
with a transformer such that the
protection settings do not expose the
transformer to fault level and duration
that exceeds its mechanical withstand
capability
• For supervisory elements as described
in PRC-023-2 - Attachment A, Section
1.6

•

For switch-on-to-fault schemes as
described in PRC-023-2 - Attachment
A, Section 1.3

Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

First day of the first
calendar quarter,
after applicable
regulatory approvals

First calendar quarter
after Board of
Trustees adoption

First day of the first
calendar quarter 12
months after
applicable regulatory
approvals

First day of the first
calendar quarter 12
months after Board
of Trustees adoption

First day of the first
calendar quarter 24
months after
applicable regulatory
approvals

First day of the first
calendar quarter 24
months after Board
of Trustees adoption

Later of the first day
of the first calendar
quarter after
applicable regulatory
approvals of PRC023-2 or the first day
of the first calendar
quarter 39 months
following applicable
regulatory approvals
of PRC-023-1
(October 1, 2013)

Later of the first day
of the first calendar
quarter after Board
of Trustees adoption
of PRC-023-2 or July
1, 2011 1

1 July 1, 2011 is the first day of the first calendar quarter 39 months following the Board of Trustees February 12,
2008 approval of PRC-023-1.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability

Effective Date
Requirement

R2 and R3

Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement R6

Later of the first day
of the first calendar
quarter 39 months
following notification
by the Planning
Coordinator of a
circuit’s inclusion on
a list of circuits
subject to PRC-023-2
per application of
Attachment B, or the
first day of the first
calendar year in
which any criterion in
Attachment B
applies, unless the
Planning Coordinator
removes the circuit
from the list before
the applicable
effective date

Each Transmission Owner, Generator
Owner, and Distribution Provider with
transmission lines operating at 200 kV and
above and transformers with low voltage
terminals connected at 200 kV and above
Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement R6

First day of the first
calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter
after Board of
Trustees adoption

Applicability

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability

Effective Date
Requirement

Applicability

Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

which any criterion in
Attachment B
applies, unless the
Planning Coordinator
removes the circuit
from the list before
the applicable
effective date

Each Transmission Owner, Generator
Owner, and Distribution Provider that
chooses to use Requirement R1 criterion 2
as the basis for verifying transmission line
relay loadability

First day of the first
calendar quarter six
months after
applicable regulatory
approvals

First day of the first
calendar quarter six
months after Board
of Trustees adoption

Each Transmission Owner, Generator
Owner, and Distribution Provider that sets
transmission line relays according to
Requirement R1 criterion 12

First day of the first
calendar quarter six
months after
applicable regulatory
approvals

First day of the first
calendar quarter six
months after Board
of Trustees adoption

Each Planning Coordinator shall conduct
an assessment by applying the criteria in
Attachment B to determine the circuits in
its Planning Coordinator area for which
Transmission Owners, Generator Owners,
and Distribution Providers must comply
with Requirements R1 through R5

First day of the first
calendar quarter 18
months after
applicable regulatory
approvals

First day of the first
calendar quarter 18
months after Board
of Trustees adoption

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability

B. Requirements
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1, criteria 1 through 13) for any specific circuit terminal
to prevent its phase protective relay settings from limiting transmission system loadability
while maintaining reliable protection of the BES for all fault conditions. Each Transmission
Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per
unit voltage and a power factor angle of 30 degrees. [Violation Risk Factor: High] [Time
Horizon: Long Term Planning].
Criteria:
1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal
Facility Rating of a circuit, for the available defined loading duration nearest 4 hours
(expressed in amperes).
2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal
15-minute Facility Rating 2 of a circuit (expressed in amperes).
3. Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:
•

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at each
end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate
at or below the maximum power transfer capability of the line, determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with Requirement R1, criterion 3, using the full
line inductive reactance.

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
8. Set transmission line relays applied on the bulk system-end of transmission lines that serve
load remote to the system so they do not operate at or below 115% of the maximum current
flow from the system to the load under any system configuration.
9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the load to the system under any system configuration.
10. Set transformer fault protection relays and transmission line relays on transmission lines
terminated only with a transformer so that the relays do not operate at or below the greater
of:
•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

•

115% of the highest operator established emergency transformer rating

10.1

Set load responsive transformer fault protection relays, if used, such that the
protection settings do not expose the transformer to a fault level and duration that
exceeds the transformer’s mechanical withstand capability3.

11. For transformer overload protection relays that do not comply with the loadability
component of Requirement R1, criterion 10 set the relays according to one of the
following:
•

Set the relays to allow the transformer to be operated at an overload level of at least
150% of the maximum applicable nameplate rating, or 115% of the highest operator
established emergency transformer rating, whichever is greater, for at least 15
minutes to provide time for the operator to take controlled action to relieve the
overload.

•

Install supervision for the relays using either a top oil or simulated winding hot spot
temperature element set no less than 100° C for the top oil temperature or no less
than 140° C for the winding hot spot temperature 4.

As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer
Through-Fault-Current Duration, Clause 4.4, Figure 4
4

IEEE standard C57.91, Tables 7 and 8, specify that transformers are to be designed to withstand a winding hot spot
temperature of 180 degrees C, and Annex A cautions that bubble formation may occur above 140 degrees C.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
c. Include a relay setting component of 87% of the current calculated in Requirement
R1, criterion 12 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

Each Transmission Owner, Generator Owner, and Distribution Provider shall set its out-of-step
blocking elements to allow tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per Requirement R1.
[Violation Risk Factor: High] [Time Horizon: Long Term Planning]

R3.

Each Transmission Owner, Generator Owner, and Distribution Provider that uses a circuit
capability with the practical limitations described in Requirement R1, criterion 6, 7, 8, 9, 12, or
13 shall use the calculated circuit capability as the Facility Rating of the circuit and shall obtain
the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator
with the calculated circuit capability. [Violation Risk Factor: Medium] [Time Horizon: Long
Term Planning]

R4.

Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to use
Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability shall
provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an
updated list of circuits associated with those transmission line relays at least once each calendar
year, with no more than 15 months between reports. [Violation Risk Factor: Lower] [Time
Horizon: Long Term Planning]

R5.

Each Transmission Owner, Generator Owner, and Distribution Provider that sets transmission
line relays according to Requirement R1 criterion 12 shall provide an updated list of the
circuits associated with those relays to its Regional Entity at least once each calendar year, with
no more than 15 months between reports, to allow the ERO to compile a list of all circuits that
have protective relay settings that limit circuit capability. [Violation Risk Factor: Lower]
[Time Horizon: Long Term Planning]

R6.

Each Planning Coordinator shall conduct an assessment at least once each calendar year, with
no more than 15 months between assessments, by applying the criteria in Attachment B to
determine the circuits in its Planning Coordinator area for which Transmission Owners,
Generator Owners, and Distribution Providers must comply with Requirements R1 through R5.
The Planning Coordinator shall: [Violation Risk Factor: High] [Time Horizon: Long Term
Planning]
6.1

Maintain a list of circuits subject to PRC-023-2 per application of Attachment B,
including identification of the first calendar year in which any criterion in Attachment
B applies.

6.2

Provide the list of circuits to all Regional Entities, Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within its
Planning Coordinator area within 30 calendar days of the establishment of the initial
list and within 30 calendar days of any changes to that list.

C. Measures
M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as spreadsheets or summaries of calculations to show that each of its transmission relays
is set according to one of the criteria in Requirement R1, criterion 1 through 13 and shall have
evidence such as coordination curves or summaries of calculations that show that relays set per
criterion 10 do not expose the transformer to fault levels and durations beyond those indicated
in the standard. (R1)
Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking
elements is set to allow tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per Requirement R1. (R2)
M3. Each Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence such
as Facility Rating spreadsheets or Facility Rating database to show that it used the calculated
circuit capability as the Facility Rating of the circuit and evidence such as dated
correspondence that the resulting Facility Rating was agreed to by its associated Planning
Coordinator, Transmission Operator, and Reliability Coordinator. (R3)
M4. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 2 shall have evidence such as dated
correspondence to show that it provided its Planning Coordinator, Transmission Operator, and
Reliability Coordinator with an updated list of circuits associated with those transmission line
relays within the required timeframe. The updated list may either be a full list, a list of
incremental changes to the previous list, or a statement that there are no changes to the
previous list. (R4)
M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided an updated list of the circuits associated with those relays to its
Regional Entity within the required timeframe. The updated list may either be a full list, a list
of incremental changes to the previous list, or a statement that there are no changes to the
previous list. (R5)
M6. Each Planning Coordinator shall have evidence such as power flow results, calculation
summaries, or study reports that it used the criteria established within Attachment B to
determine the circuits in its Planning Coordinator area for which applicable entities must
comply with the standard as described in Requirement R6. The Planning Coordinator shall
have a dated list of such circuits and shall have evidence such as dated correspondence that it
provided the list to the Regional Entities, Reliability Coordinators, Transmission Owners,
Generator Owners, and Distribution Providers within its Planning Coordinator area within the
required timeframe.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
•

For entities that do not work for the Regional Entity, the Regional Entity shall serve as
the Compliance Enforcement Authority.
For functional entities that work for their Regional Entity, the ERO shall serve as the
Compliance Enforcement Authority.

•

1.2. Data Retention
The Transmission Owner, Generator Owner, Distribution Provider and Planning Coordinator
shall keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation to demonstrate compliance with Requirements R1 through R5 for three
calendar years.
The Planning Coordinator shall retain documentation of the most recent review process
required in R6. The Planning Coordinator shall retain the most recent list of circuits in its
Planning Coordinator area for which applicable entities must comply with the standard, as
determined per R6.
If a Transmission Owner, Generator Owner, Distribution Provider or Planning Coordinator is
found non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time specified above, whichever is longer.
The Compliance Monitor shall keep the last audit record and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
None.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability

Violation Severity Levels:

Requirement
R1

Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity did not use
any one of the following criteria
(Requirement R1 criterion 1
through 13) for any specific circuit
terminal to prevent its phase
protective relay settings from
limiting transmission system
loadability while maintaining
reliable protection of the Bulk
Electric System for all fault
conditions.
OR
The responsible entity did not
evaluate relay loadability at 0.85
per unit voltage and a power factor
angle of 30 degrees.

N/A

The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that
occur during the loading
conditions used to verify
transmission line relay loadability
per Requirement R1.

N/A

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with an
updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

The responsible entity did not
provide its Regional Entity, with
an updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 12 at least once each
calendar year, with no more than
15 months between reports.

N/A

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

OR
The Planning Coordinator used the
criteria established within
11

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate
OR

OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 and 6.2 but provided the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area
between 31 days and 45 days after
the list was established or updated.
(part 6.2)

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

High

Severe
Attachment B, at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to meet parts 6.1 and 6.2.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to maintain the list of
circuits determined according to
the process described in
Requirement R6. (part 6.1)
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 but failed to provide the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
12

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
Planning Coordinator area or
provided the list more than 60
days after the list was established
or updated. (part 6.2)
OR
The Planning Coordinator failed to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, June
2008, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at:
http://www.nerc.com/fileUploads/File/Standards/Relay_Loadability_Reference_Doc_Clean_Fina
l_2008July3.pdf
.
Version History
Version

Date

Action

Change Tracking

February 12, 2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe VSL
for Requirement 3 — “then” should be “than.”

Errata

1
1

March 18, 2010
April 19, 2010

March 10, 2011

Approved by FERC
Filed for approval
Changed VRF for R3 from Medium to High;
changed VSLs for R1, R2, R3 to binary Severe
to comply with Order 733
Approved by Board of Trustees
Revised to address initial set of directives from
Order 733

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Revision

Revision (Project
2010-13)

Standard PRC-023-2 — Transmission Relay Loadability
PRC-023 — Attachment A
1. This standard includes any protective functions which could trip with or without time delay, on load
current, including but not limited to:
1.1. Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided protection schemes including but not limited to:
1.5.1

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

1.6. Phase overcurrent supervisory elements (i.e., phase fault detectors) associated with currentbased, communication-assisted schemes (i.e., pilot wire, phase comparison, and line current
differential) where the scheme is capable of tripping for loss of communications.
2. The following protection systems are excluded from requirements of this standard:
2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications except as noted in
section 1.6

2.2. Protection systems intended for the detection of ground fault conditions.
2.3. Protection systems intended for protection during stable power swings.
2.4. Generator protection relays that are susceptible to load.
2.5. Relay elements used only for Special Protection Systems applied and approved in accordance
with NERC Reliability Standards PRC-012 through PRC-017 or their successors.
2.6. Protection systems that are designed only to respond in time periods which allow 15 minutes or
greater to respond to overload conditions.
2.7. Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.
2.8. Relay elements associated with dc lines.
2.9. Relay elements associated with dc converter transformers.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
PRC-023 — Attachment B
Circuits to Evaluate

•
•

Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals
connected at 100 kV to 200 kV.
Transmission lines operated below 100 kV and transformers with low voltage terminals
connected below 100 kV that are part of the BES.

Criteria
If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for
that circuit.
B1. The circuit is a monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Québec Interconnection, that has been included to address
reliability concerns for loading of that circuit, as confirmed by the applicable Planning
Coordinator.
B2. The circuit is a monitored Facility of an IROL, where the IROL was determined in the planning
horizon pursuant to FAC-010.
B3. The circuit forms a path (as agreed to by the Generator Operator and the transmission entity) to
supply off-site power to a nuclear plant as established in the Nuclear Plant Interface
Requirements (NPIRs) pursuant to NUC-001.
B4. The circuit is identified through the following sequence of power flow analyses 5 performed by the
Planning Coordinator for the one-to-five-year planning horizon:
a. Simulate double contingency combinations selected by engineering judgment, without
manual system adjustments in between the two contingencies (reflects a situation where a
System Operator may not have time between the two contingencies to make appropriate
system adjustments).
b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in
consultation with the Facility owner, against a threshold based on the Facility Rating assigned
for that circuit and used in the power flow case by the Planning Coordinator.
c. When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.
d. The threshold for selection of the circuit will vary based on the loading duration assumed in
the development of the Facility Rating.

Past analyses may be used to support the assessment if no material changes to the system have occurred since the
last assessment

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-2 — Transmission Relay Loadability
i.

If the Facility Rating is based on a loading duration of up to and including four hours,
the circuit must comply with the standard if the loading exceeds 115% of the Facility
Rating.

ii.

If the Facility Rating is based on a loading duration greater than four and up to and
including eight hours, the circuit must comply with the standard if the loading
exceeds 120% of the Facility Rating.

iii.

If the Facility Rating is based on a loading duration of greater than eight hours, the
circuit must comply with the standard if the loading exceeds 130% of the Facility
Rating.

e. Radially operated circuits serving only load are excluded.
B5. The circuit is selected by the Planning Coordinator based on technical studies or assessments,
other than those specified in criteria B1 through B4, in consultation with the Facility owner.
B6. The circuit is mutually agreed upon for inclusion by the Planning Coordinator and the Facility
owner.

Approved by Board of Trustees: March 10, 2011
Effective Date: TBD

Standard PRC-023-12 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-12

3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with
system operators’ ability to take remedial action to protect system reliability and; be set to
reliably detect all fault conditions and protect the electrical network from these faults.
4. Applicability:
4.1. Functional Entity
4.1.4.1.1 Transmission Owners with load-responsive phase protection systems as
described in PRC-023-2 - Attachment A, applied to facilitiescircuits defined below: in
4.2.1 (Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.3 Distribution Providers with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1(Circuits Subject to
Requirements R1 – R5), provided those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinators
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.1.14.2.1.1 Transmission lines operated at 200 kV and above.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV as designatedselected by the
Planning Coordinator as critical to the reliabilityin accordance with R6.
4.1.24.2.1.3 Transmission lines operated below 100 kV that are part of the Bulk
Electric System.BES and selected by the Planning Coordinator in accordance
with R6.
4.1.34.2.1.4 Transformers with low voltage terminals connected at 200 kV and above.
4.1.44.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV
as designatedselected by the Planning Coordinator as critical to the reliability
of the Bulk Electric Systemin accordance with R6.
4.2. Generator OwnersTransformers with load-responsive phase protection systems as described
in Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.
4.3. Distribution Providers with load-responsive phase protection systems as described in
Attachment A, applied according to facilities defined in 4.1.1 through 4.1.4., providedlow
voltage terminals connected below 100 kV that those facilities have bi-directional flow
capabilities.
4.4. Planning Coordinators.

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability
5. Effective Dates 1:

TBD

5.1. Requirement 1, Requirement 2:
5.1.1 For circuits described in 4.1.1 and 4.1.3 above (except for switch-on-to-fault
schemes) —the beginningare part of the first calendar quarter following applicable
regulatory approvals.
5.1.2 For circuits described in 4.1.2 and 4.1.4 above (including switch-on-to-fault
schemes) — at the beginning of the first calendar quarter 39 months following
applicable regulatory approvals.
5.1.34.2.1.6 Each Transmission Owner, Generator Owner, and Distribution Provider
shall have 24 months after being notifiedBES and selected by itsthe Planning
Coordinator pursuant to R3.3 to comply with R1 (including all subrequirements) for each facility that is added to the Planning Coordinator’s
critical facilities list determined pursuant to R3.1in accordance with R6.
4.2.2 Circuits Subject to Requirement 3: 18 monthsR6
4.2.2.1 Transmission lines operated at 100 kV to 200 kV and transformers with low
voltage terminals connected at 100 kV to 200 kV
4.2.2.2 Transmission lines operated below100 kV and transformers with low voltage
terminals connected below 100 kV that are part of the BES
5.

Effective Dates

5.2.
The effective dates of the requirements in the PRC-023-2 standard corresponding to the
applicable Functional Entities and circuits are summarized in the following applicable regulatory
approvals.table:

Effective Date
Requirement

Applicability

Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

First day of the first
calendar quarter,
after applicable
regulatory approvals

First calendar quarter
after Board of
Trustees adoption

First day of the first
calendar quarter 12

1 Temporary Exceptions that have already been approved by the NERC Planning Committee via the NERC System
Protection and Control Task Force prior to the approval of this standard shall not result in either findings of noncompliance or sanctions if all of the following apply: (1) the approved requests for Temporary Exceptions include a
mitigation plan (including schedule) to come into full compliance, and (2) the non-conforming relay settings are
mitigated according to the approved mitigation plan.

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability

Effective Date
Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

on transmission lines terminated only
with a transformer such that the
protection settings do not expose the
transformer to fault level and duration
that exceeds its mechanical withstand
capability
For supervisory elements as described
in PRC-023-2 - Attachment A, Section
1.6

months after
applicable regulatory
approvals

months after Board
of Trustees adoption

First day of the first
calendar quarter 24
months after
applicable regulatory
approvals

First day of the first
calendar quarter 24
months after Board
of Trustees adoption

For switch-on-to-fault schemes as
described in PRC-023-2 - Attachment
A, Section 1.3

Later of the first day
of the first calendar
quarter after Board
of Trustees adoption
of PRC-023-2 or July
1, 2011 2

Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement R6

Requirement

Applicability

•

2 July 1, 2011 is the first day of the first calendar quarter 39 months following the Board of Trustees February 12,
2008 approval of PRC-023-1.

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability

Effective Date
Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

which any criterion in
Attachment B
applies, unless the
Planning Coordinator
removes the circuit
from the list before
the applicable
effective date

Each Transmission Owner, Generator
Owner, and Distribution Provider with
transmission lines operating at 200 kV and
above and transformers with low voltage
terminals connected at 200 kV and above
Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement R6

First day of the first
calendar quarter
after applicable
regulatory approvals

First day of the first
calendar quarter
after Board of
Trustees adoption

Each Transmission Owner, Generator
Owner, and Distribution Provider that

First day of the first
calendar quarter six

Requirement

Applicability

R2 and R3

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability

Effective Date
Jurisdictions where
Regulatory
Approval is
Required

Jurisdictions where
No Regulatory
Approval is
Required

chooses to use Requirement R1 criterion 2
as the basis for verifying transmission line
relay loadability

months after
applicable regulatory
approvals

months after Board
of Trustees adoption

Each Transmission Owner, Generator
Owner, and Distribution Provider that sets
transmission line relays according to
Requirement R1 criterion 12

First day of the first
calendar quarter six
months after
applicable regulatory
approvals

First day of the first
calendar quarter six
months after Board
of Trustees adoption

First day of the first
calendar quarter 18
months after
applicable regulatory
approvals

First day of the first
calendar quarter 18
months after Board
of Trustees adoption

Requirement

Applicability

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability

B. Requirements
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1., criteria 1 through R1.13) for any specific circuit
terminal to prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the Bulk Electric SystemBES for all fault
conditions. Each Transmission Owner, Generator Owner, and Distribution Provider shall
evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees:.
[Violation Risk Factor: High] [Mitigation Time Horizon: Long Term Planning].
Criteria:
R1.1.1.
Set transmission line relays so they do not operate at or below 150% of the
highest seasonal Facility Rating of a circuit, for the available defined loading duration
nearest 4 hours (expressed in amperes).
R1.2.2.
Set transmission line relays so they do not operate at or below 115% of the
highest seasonal 15-minute Facility Rating3 of a circuit (expressed in amperes).
R1.3.3.
Set transmission line relays so they do not operate at or below 115% of the
maximum theoretical power transfer capability (using a 90-degree angle between the
sending-end and receiving-end voltages and either reactance or complex impedance) of the
circuit (expressed in amperes) using one of the following to perform the power transfer
calculation:
1.3.1• An infinite source (zero source impedance) with a 1.00 per unit bus voltage at
each end of the line.
1.3.2• An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.
R1.4.4.
Set transmission line relays on series compensated transmission lines so
they do not operate at or below the maximum power transfer capability of the line,
determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

-• 115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with R1.Requirement R1, criterion 3, using the
full line inductive reactance.
R1.5.5.
Set transmission line relays on weak source systems so they do not operate
at or below 170% of the maximum end-of-line three-phase fault magnitude (expressed in
amperes).
R1.6.6.
Set transmission line relays applied on transmission lines connected to
generation stations remote to load so they do not operate at or below 230% of the
aggregated generation nameplate capability.

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability
R1.7.7.
Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current flow
from the load to the generation source under any system configuration.
R1.8.8.
Set transmission line relays applied on the bulk system-end of transmission
lines that serve load remote to the system so they do not operate at or below 115% of the
maximum current flow from the system to the load under any system configuration.
R1.9.9.
Set transmission line relays applied on the load-end of transmission lines
that serve load remote to the bulk system so they do not operate at or below 115% of the
maximum current flow from the load to the system under any system configuration.
R1.10.10.
Set transformer fault protection relays and transmission line relays on
transmission lines terminated only with a transformer so that theythe relays do not operate
at or below the greater of:
-• 150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.
-• 115% of the highest operator established emergency transformer rating.
10.1

R1.11.11.
For transformer overload protection relays that do not comply with R1.the
loadability component of Requirement R1, criterion 10 set the relays according to one of
the following:
-• Set the relays to allow the transformer to be operated at an overload level of at least
150% of the maximum applicable nameplate rating, or 115% of the highest operator
established emergency transformer rating, whichever is greater. The protection must
allow this overload, for at least 15 minutes to allowprovide time for the operator to
take controlled action to relieve the overload.
-• Install supervision for the relays using either a top oil or simulated winding hot spot
temperature element. The setting should be set no less than 100° C for the top oil
ortemperature or no less than 140° C for the winding hot spot temperature 5.
R1.12.12.
When the desired transmission line capability is limited by the requirement
to adequately protect the transmission line, set the transmission line distance relays to a
maximum of 125% of the apparent impedance (at the impedance angle of the transmission
line) subject to the following constraints:
R1.12.1.a.
Set the maximum torque angle (MTA) to 90 degrees or the highest
supported by the manufacturer.
4

As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer
Through-Fault-Current Duration, Clause 4.4, Figure 4
5

IEEE standard C57.115, Table 3, specifies91, Tables 7 and 8, specify that transformers are to be designed to
withstand a winding hot spot temperature of 180 degrees C, and Annex A cautions that bubble formation may occur
above 140 degrees C.

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability
R1.12.2.b.
Evaluate the relay loadability in amperes at the relay trip point at 0.85
per unit voltage and a power factor angle of 30 degrees.
R1.12.3.c.
Include a relay setting component of 87% of the current calculated in
Requirement R1., criterion 12.2 in the Facility Rating determination for the circuit.
R1.13.13.
Where other situations present practical limitations on circuit capability, set
the phase protection relays so they do not operate at or below 115% of such limitations.
R2.

TheEach Transmission Owner, Generator Owner, orand Distribution Provider shall set its outof-step blocking elements to allow tripping of phase protective relays for faults that occur
during the loading conditions used to verify transmission line relay loadability per Requirement
R1. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

R2.R3.
Each Transmission Owner, Generator Owner, and Distribution Provider that
uses a circuit capability with the practical limitations described in R1.Requirement R1,
criterion 6, R1.7, R1.8, R1.9, R1.12, or R1.13 shall use the calculated circuit capability as the
Facility Rating of the circuit and shall obtain the agreement of the Planning Coordinator,
Transmission Operator, and Reliability Coordinator with the calculated circuit capability.
[Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
R3.R4.
The Planning Coordinator shall determine which of the facilities
(transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals
connected at 100 kV to 200 kV) in its Planning Coordinator Area are critical to the reliability
of the Bulk Electric System to identify the facilities from 100 kV to 200 kVEach Transmission
Owner, Generator Owner, and Distribution Provider that must meetchooses to use Requirement
1 to prevent potential cascade tripping that may occur when protective relay settings limit
transmission R1 criterion 2 as the basis for verifying transmission line relay loadability shall
provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an
updated list of circuits associated with those transmission line relays at least once each calendar
year, with no more than 15 months between reports. [Violation Risk Factor: MediumLower]
[Time Horizon: Long Term Planning]
R5.

TheEach Transmission Owner, Generator Owner, and Distribution Provider that sets
transmission line relays according to Requirement R1 criterion 12 shall provide an updated list
of the circuits associated with those relays to its Regional Entity at least once each calendar
year, with no more than 15 months between reports, to allow the ERO to compile a list of all
circuits that have protective relay settings that limit circuit capability. [Violation Risk Factor:
Lower] [Time Horizon: Long Term Planning]
1.1

Each Planning Coordinator shall have a processconduct an assessment at least once
each calendar year, with no more than 15 months between assessments, by applying
the criteria in Attachment B to determine the facilities that are critical to the reliability
of the Bulk Electric System.
1.3.1

1.2
R6.

This process shall consider input from adjoining Planning Coordinators and
affected Reliability Coordinators.

Thecircuits in its Planning Coordinator shall maintain a current list of facilities
determined according to the process described in R3.1.

Thearea for which Transmission Owners, Generator Owners, and Distribution Providers must
comply with Requirements R1 through R5. The Planning Coordinator shall: [Violation Risk
Factor: High] [Time Horizon: Long Term Planning Coordinator shall provide a list of facilities
to its]

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability
6.1

Maintain a list of circuits subject to PRC-023-2 per application of Attachment B,
including identification of the first calendar year in which any criterion in Attachment
B applies.

R3.3.6.2 Provide the list of circuits to all Regional Entities, Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within 30its
Planning Coordinator area within 30 calendar days of the establishment of the initial
list and within 30 calendar days of any changes to thethat list.
C. Measures
M1. TheEach Transmission Owner, Generator Owner, and Distribution Provider shall each have
evidence such as spreadsheets or summaries of calculations to show that each of its
transmission relays areis set according to one of the criteria in R1.Requirement R1, criterion 1
through 13 and shall have evidence such as coordination curves or summaries of calculations
that show that relays set per criterion 10 do not expose the transformer to fault levels and
durations beyond those indicated in the standard. (R1.13. ()
M1.M2.
Each Transmission Owner, Generator Owner, and Distribution Provider
shall have evidence such as spreadsheets or summaries of calculations to show that each of its
out-of-step blocking elements is set to allow tripping of phase protective relays for faults that
occur during the loading conditions used to verify transmission line relay loadability per
Requirement R1. (R2)
M2.M3.
TheEach Transmission Owner, Generator Owner, and Distribution Provider
with transmission relays set according to the criteria inRequirement R1., criterion 6, R1.7,
R1.8, R1.9, R1.12, or R.13 shall have evidence such as Facility Rating spreadsheets or Facility
Rating database to show that it used the calculated circuit capability as the Facility Rating of
the circuit and evidence such as dated correspondence that the resulting Facility Rating was
agreed to by its associated Planning Coordinator, Transmission Operator, and Reliability
Coordinator. (R2R3)
M4. The Each Transmission Owner, Generator Owner, or Distribution Provider that sets
transmission line relays according to Requirement R1, criterion 2 shall have evidence such as
dated correspondence to show that it provided its Planning Coordinator shall have,
Transmission Operator, and Reliability Coordinator with an updated list of circuits associated
with those transmission line relays within the required timeframe. The updated list may either
be a documented process for the determination of facilities as described in R3full list, a list of
incremental changes to the previous list, or a statement that there are no changes to the
previous list. (R4)
M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided an updated list of the circuits associated with those relays to its
Regional Entity within the required timeframe. The updated list may either be a full list, a list
of incremental changes to the previous list, or a statement that there are no changes to the
previous list. (R5)
M3.M6.
Each Planning Coordinator shall have evidence such as power flow results,
calculation summaries, or study reports that it used the criteria established within Attachment B
to determine the circuits in its Planning Coordinator area for which applicable entities must
comply with the standard as described in Requirement R6. The Planning Coordinator shall
have a currentdated list of such facilitiescircuits and shall have evidence such as dated
correspondence that it provided the list to the approriateRegional Entities, Reliability

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability
Coordinators, Transmission OperatorsOwners, Generator OperatorsOwners, and Distribution
Providers. (R3) within its Planning Coordinator area within the required timeframe.

Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
1.1.1•
For entities that do not work for the Regional Entity, the Regional Entity
shall serve as the Compliance Enforcement Authority.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
•

For functional entities that work for their Regional Entity, the ERO shall serve as the
Compliance Enforcement Authority.

1.3.1.2.

Data Retention

The Transmission Owner, Generator Owner, Distribution Provider and Planning Coordinator
shall keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation to demonstrate compliance with Requirements R1 through R5 for three
calendar years.
The Planning Coordinator shall retain documentation of the most recent review process
required in R3R6. The Planning Coordinator shall retain the most recent list of facilities that
are critical to circuits in its Planning Coordinator area for which applicable entities must
comply with the reliability of the electric systemstandard, as determined per R3R6.
If a Transmission Owner, Generator Owner, Distribution Provider or Planning Coordinator is
found non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time specified above, whichever is longer.
The Compliance Monitor shall retain its compliance documentation for three yearskeep the
last audit record and all requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
The Transmission Owner, Generator Owner, Planning Coordinator, and Distribution Provider
shall each demonstrate compliance through annual self-certification, or compliance audit
(periodic, as part of targeted monitoring or initiated by complaint or event), as determined by
the Compliance Enforcement Authority.
Ap p ro ve d b y Bo a rd o f Tru s te e s : Fe b ru a ry 12, 2008 Ma rc h 10, 2011
Effe c tive Da te : TBD

Standard PRC-023-12 — Transmission Relay Loadability
None.

Violation Severity Levels:

Requirement
R1

Lower
N/A

Moderate
Evidence that relay settings
comply with criteria in R1.1
though 1.13 exists, but evidence is
incomplete or incorrect for one or
more of the subrequirements. N/A

High
N/A

Severe
Relay settings do not comply with
any of the sub requirements R1.1
through R1.13
OR
Evidence does not exist to support
that relay settings comply with
one of the criteria in
subrequirements R1.1 through
R1.13.The responsible entity did
not use any one of the following
criteria (Requirement R1 criterion
1 through 13) for any specific
circuit terminal to prevent its
phase protective relay settings
from limiting transmission system
loadability while maintaining
reliable protection of the Bulk
Electric System for all fault
conditions.
OR
The responsible entity did not
evaluate relay loadability at 0.85
per unit voltage and a power factor
angle of 30 degrees.

N/A

Approved by Board of Trustees: Fe b ru a ry 12, 2008 March 10, 2011
Effective Date: TBD

N/A

The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that
occur during the loading
conditions used to verify
transmission line relay loadability
12

Standard PRC-023-12 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
per Requirement R1.

R2R3

Criteria described in R1.6, R1.7.
R1.8. R1.9, R1.12, or R.13 was
used but evidence does not exist
that agreement was obtained in
accordance with R2.N/A

N/A

The responsible entity that uses a
circuit capability with the practical
limitations described in
Requirement R1 criterion 6, 7, 8,
9, 12, or 13 did not use the
calculated circuit capability as the
Facility Rating of the circuit.
OR
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with an
updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

The responsible entity did not
provide its Regional Entity, with
an updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 12 at least once each
calendar year, with no more than
15 months between reports.

Approved by Board of Trustees: Fe b ru a ry 12, 2008 March 10, 2011
Effective Date: TBD

Standard PRC-023-12 — Transmission Relay Loadability
Requirement
R3R6

Lower
N/A

Moderate

High

Provided the list of facilities
criticalThe Planning Coordinator
used the criteria established within
Attachment B to determine the
reliability ofcircuits in its Planning
Coordinator area for which
applicable entities must comply
with the Bulk Electric
Systemstandard and met parts 6.1
and 6.2, but more than 15 months
and less than 24 months lapsed
between assessments.

OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
the appropriatedetermine the
circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.1 and
6.2 but failed to include the
calendar year in which any
criterion in Attachment B first
applies.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must

Approved by Board of Trustees: Fe b ru a ry 12, 2008 March 10, 2011
Effective Date: TBD

Severe
Does not have a process in place
to determine facilities that are
critical to the reliability of the
Bulk Electric System.
The Planning Coordinator failed to
use the criteria established within
Attachment B to determine the
circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard.
OR

OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
the appropriatedetermine the
circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.1 and
6.2 but provided the list of circuits
to the Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution
Providers within its Planning
Coordinator area between 46 days
and 60 days after list was
established or updated. (part 6.2)

Does not maintain a current list of
facilities critical to the reliability
of the Bulk Electric System,
OR
Did notThe Planning Coordinator
used the criteria established within
Attachment B, at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to meet parts 6.1 and 6.2.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
14

Standard PRC-023-12 — Transmission Relay Loadability
Requirement

Lower

Moderate
comply with the standard and met
6.1 and 6.2 but provided the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area
between 31 days and 45 days after
the list was established or updated.
(part 6.2)

High

Severe
comply with the standard but
failed to maintain the list of
circuits determined according to
the process described in
Requirement R6. (part 6.1)
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 but failed to provide the list of
facilities critical to the reliability
of the Bulk Electric System to the
appropriatecircuits to the
Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution
Providers, within its Planning
Coordinator area or provided the
list more than 60 days after the list
was established or updated. (part
6.2)
OR
The Planning Coordinator failed to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard.

Approved by Board of Trustees: Fe b ru a ry 12, 2008 March 10, 2011
Effective Date: TBD

Standard PRC-023-12 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007June 2008, prepared by the System Protection and Control Task Force of the NERC
Planning Committee, available at:
http://www.nerc.com/~filez/reports.html/fileUploads/File/Standards/Relay_Loadability_Referenc
e_Doc_Clean_Final_2008July3.pdf .
.
Version History
Version

Date

Action

Change Tracking

February 12, 2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe VSL
for Requirement 3 — “then” should be “than.”

Errata

1
1

March 18, 2010
April 19, 2010

March 10, 2011

Approved by Board of Trustees: February 12 ,2008
Effective Date: TBD

Revision

Revision (Project
2010-13)

Standard PRC-023-12 — Transmission Relay Loadability
PRC-023 — Attachment A
1. This standard includes any protective functions which could trip with or without time delay, on load
current, including but not limited to:
1.1. Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided protection schemes including but not limited to:

1.5.1

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

This standard includes out-of-step blocking schemes which shall be evaluated to ensure that they
do not block trip for faults during the loading conditions defined within the requirements.
1.6. Phase overcurrent supervisory elements (i.e., phase fault detectors) associated with currentbased, communication-assisted schemes (i.e., pilot wire, phase comparison, and line current
differential) where the scheme is capable of tripping for loss of communications.

3.2. The following protection systems are excluded from requirements of this standard:
3.1.2.1.
Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications. except as noted in
section 1.6

3.2.2.2.

Protection systems intended for the detection of ground fault conditions.

3.3.2.3.

Protection systems intended for protection during stable power swings.

3.4.2.4.

Generator protection relays that are susceptible to load.

3.5.2.5.
Relay elements used only for Special Protection Systems applied and approved in
accordance with NERC Reliability Standards PRC-012 through PRC-017 or their successors.
3.6.2.6.
Protection systems that are designed only to respond in time periods which allow
operators 15 minutes or greater to respond to overload conditions.
3.7.2.7.

Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.

3.8.2.8.

Relay elements associated with DCdc lines.

3.9.2.9.

Relay elements associated with DCdc converter transformers.

Approved by Board of Trustees: February 12 ,2008
Effective Date: TBD

Standard PRC-023-12 — Transmission Relay Loadability
PRC-023 — Attachment B
Circuits to Evaluate

•
•

Criteria
If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for
that circuit.
B1. The circuit is a monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Québec Interconnection, that has been included to address
reliability concerns for loading of that circuit, as confirmed by the applicable Planning
Coordinator.
B2. The circuit is a monitored Facility of an IROL, where the IROL was determined in the planning
horizon pursuant to FAC-010.
B3. The circuit forms a path (as agreed to by the Generator Operator and the transmission entity) to
supply off-site power to a nuclear plant as established in the Nuclear Plant Interface
Requirements (NPIRs) pursuant to NUC-001.
B4. The circuit is identified through the following sequence of power flow analyses 6 performed by the
Planning Coordinator for the one-to-five-year planning horizon:
a. Simulate double contingency combinations selected by engineering judgment, without
manual system adjustments in between the two contingencies (reflects a situation where a
System Operator may not have time between the two contingencies to make appropriate
system adjustments).
b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in
consultation with the Facility owner, against a threshold based on the Facility Rating assigned
for that circuit and used in the power flow case by the Planning Coordinator.
c. When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.
d. The threshold for selection of the circuit will vary based on the loading duration assumed in
the development of the Facility Rating.

Past analyses may be used to support the assessment if no material changes to the system have occurred since the
last assessment

Approved by Board of Trustees: February 12 ,2008
Effective Date: TBD

Standard PRC-023-12 — Transmission Relay Loadability
i.

If the Facility Rating is based on a loading duration of up to and including four hours,
the circuit must comply with the standard if the loading exceeds 115% of the Facility
Rating.

ii.

iii.

If the Facility Rating is based on a loading duration of greater than eight hours, the
circuit must comply with the standard if the loading exceeds 130% of the Facility
Rating.

Approved by Board of Trustees: February 12 ,2008
Effective Date: TBD

Exhibit B
Implementation Plan for PRC-023-2 submitted for approval

Implementation Plan for PRC-023-2: Transmission Relay Loadability
Standards Involved

•

PRC-023-2 —Transmission Relay Loadability

Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before the Transmission Relay Loadability standard can be
implemented.
Proposed Effective Dates
The effective dates of the requirements in the PRC-023-2 standard corresponding to the applicable
Functional Entities and circuits are summarized in the following table:

Requirement

Applicability

Each Transmission Owner, Generator
Owner, and Distribution Provider with
transmission lines operating at 200 kV
and above and transformers with low
voltage terminals connected at 200 kV
and above, except as noted below.
• For Requirement R1, criterion 10.1,
to set transformer fault protection
relays on transmission lines
terminated only with a transformer
such that the protection settings do
not expose the transformer to fault
level and duration that exceeds its
mechanical withstand capability
• For supervisory elements as
described in PRC-023-2 Attachment A, Section 1.6
•

For switch-on-to-fault schemes as
described in PRC-023-2 Attachment A, Section 1.3

Effective Date
Jurisdictions where Jurisdictions where
Regulatory
No Regulatory
Approval is
Approval is
Required
Required
First day of the first
First calendar
calendar quarter,
quarter after Board
after applicable
of Trustees adoption
regulatory approvals

First day of the first
calendar quarter 12
months after
applicable regulatory
approvals

First day of the first
calendar quarter 12
months after Board
of Trustees adoption

First day of the first
calendar quarter 24
months after
applicable regulatory
approvals
Later of the first day
of the first calendar
quarter after
applicable regulatory
approvals of PRC023-2 or the first day

First day of the first
calendar quarter 24
months after Board
of Trustees adoption
Later of the first day
of the first calendar
quarter after Board
of Trustees adoption
of PRC-023-2 or
July 1, 2011 1

1 July 1, 2011 is the first day of the first calendar quarter 39 months following the Board of Trustees February 12,
2008 approval of PRC-023-1.

March 8, 2011

Requirement

Applicability

Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement
R6

R2 and R3

March 8, 2011

Each Transmission Owner, Generator
Owner, and Distribution Provider with
transmission lines operating at 200 kV
and above and transformers with low
voltage terminals connected at 200 kV
and above
Each Transmission Owner, Generator
Owner, and Distribution Provider with
circuits identified by the Planning
Coordinator pursuant to Requirement
R6

Effective Date
Jurisdictions where Jurisdictions where
Regulatory
No Regulatory
Approval is
Approval is
Required
Required
of the first calendar
quarter 39 months
following applicable
regulatory approvals
of PRC-023-1
(October 1, 2013)
Later of the first day Later of the first day
of the first calendar
of the first calendar
quarter 39 months
quarter 39 months
following
following
notification by the
notification by the
Planning
Planning
Coordinator of a
Coordinator of a
circuit’s inclusion on circuit’s inclusion on
a list of circuits
a list of circuits
subject to PRC-023- subject to PRC-0232 per application of
2 per application of
Attachment B, or the Attachment B, or the
first day of the first
first day of the first
calendar year in
calendar year in
which any criterion
which any criterion
in Attachment B
in Attachment B
applies, unless the
applies, unless the
Planning
Planning
Coordinator removes Coordinator removes
the circuit from the
the circuit from the
list before the
list before the
applicable effective
applicable effective
date
date
First day of the first
calendar quarter after
applicable regulatory
approvals

First day of the first
calendar quarter
after Board of
Trustees adoption

Requirement

Applicability

Effective Date
Jurisdictions where Jurisdictions where
Regulatory
No Regulatory
Approval is
Approval is
Required
Required
Attachment B, or the Attachment B, or the
first day of the first
first day of the first
calendar year in
calendar year in
which any criterion
which any criterion
in Attachment B
in Attachment B
applies, unless the
applies, unless the
Planning
Planning
Coordinator removes Coordinator removes
the circuit from the
the circuit from the
list before the
list before the
applicable effective
applicable effective
date
date

Each Transmission Owner, Generator
Owner, and Distribution Provider that
chooses to use Requirement R1 criterion
2 as the basis for verifying transmission
line relay loadability

First day of the first
calendar quarter six
months after
applicable regulatory
approvals

First day of the first
calendar quarter six
months after Board
of Trustees adoption

Each Transmission Owner, Generator
Owner, and Distribution Provider that
sets transmission line relays according
to Requirement R1 criterion 12

First day of the first
calendar quarter six
months after
applicable regulatory
approvals

First day of the first
calendar quarter six
months after Board
of Trustees adoption

Each Planning Coordinator shall
conduct an assessment by applying the
criteria in Attachment B to determine
the circuits in its Planning Coordinator
area for which Transmission Owners,
Generator Owners, and Distribution
Providers must comply with
Requirements R1 through R5

First day of the first
calendar quarter 18
months after
applicable regulatory
approvals

First day of the first
calendar quarter 18
months after Board
of Trustees adoption

1. Applicability
1.1. Requirements within the proposed standard apply to the following:
1.1.1. Functional Entity
1.1.1.1.

1.1.1.2.

March 8, 2011

1.1.1.3.

1.1.1.4.

Distribution Providers with load-responsive phase protection systems as
described in PRC-023-2 - Attachment A, applied to circuits defined in
4.2.1(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
Planning Coordinators

1.1.2. Circuits
1.1.2.1.
Circuits Subject to Requirements R1 – R5
1.1.2.1.1.
Transmission lines operated at 200 kV and above
1.1.2.1.2.
Transmission lines operated at 100 kV to 200 kV selected by the
Planning Coordinator in accordance with R6
1.1.2.1.3.
Transmission lines operated below 100 kV that are part of the BES and
selected by the Planning Coordinator in accordance with R6
1.1.2.1.4.
Transformers with low voltage terminals connected at 200 kV and above
1.1.2.1.5.
Transformers with low voltage terminals connected at 100 kV to 200 kV
selected by the Planning Coordinator in accordance with R6
1.1.2.1.6.
Transformers with low voltage terminals connected below 100 kV that
are part of the BES and selected by the Planning Coordinator in
accordance with R6
1.1.2.2.
Circuits Subject to Requirement R6
1.1.2.2.1.
Transmission lines operated at 100 kV to 200 kV and transformers with
low voltage terminals connected at 100 kV to 200 kV
1.1.2.2.2.
Transmission lines operated below100 kV and transformers with low
voltage terminals connected below 100 kV that are part of the BES
1.2. Other entities may be recipients of data as described in this standard, but have no requirements
placed upon them
2. Implementation Dates
For circuits already identified and subject to the requirements in PRC-023-1, the existing
implementation dates will remain in effect.
3. Retired Standards
Requirement R1 of PRC-023-1 is retired the first day of the first calendar quarter after applicable
regulatory approvals, or in those jurisdictions where no regulatory approval is required, the first
calendar quarter after Board of Trustees adoption.
Requirement R2 of PRC-023-1 is retired the first day of the first calendar quarter after applicable
regulatory approvals, or in those jurisdictions where no regulatory approval is required, the first day
of the first calendar quarter after Board of Trustees adoption.
Requirement R3 of PRC-023-1 is retired the first day of the first calendar quarter 18 months after
applicable regulatory approvals, or in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
When all requirements of PRC-023-2 become effective in all jurisdictions as specified above, PRC023-1 — Transmission Relay Loadability will be retired.

March 8, 2011

Exhibit C
Standard Drafting Team Roster for Project 2010-13 Relay Loadability Order 733

Project 2010-13 Relay Loadability Order 733
Phase I Drafting Team and
Blue Ribbon Panel for PRC-023-2
Name and Title
Affiliation
Contact Info
Charles W. Rogers
Principal Engineer
Drafting Team Chair
Consumers Energy
1945 W. Parnall Road
Jackson, Michigan 49201
(517) 788-0027
cwrogers@cmsenergy.com

Baj Agrawal
Engineering Manager
Arizona Public Service Co.
2124 W. Cheryl Drive
Phoenix, AZ 85021
602-371-6386
bajarang.agrawal@aps.com
David Angell
Manager, Delivery Planning
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
(208) 388-2701
DaveAngell@idahopower.com
Gary T. Brownfield
Supervising Engineer,
Transmission Planning
Ameren Services
1901 Chouteau Avenue
MC 691
St. Louis, MO 63166-6149
314-554-2556
GBrownfield@
ameren.com

Bio

Charles Rogers is a Principal Engineer at Consumers Energy, where he has been employed
since 1978. For the bulk of his career, Charles has been responsible for application of
protective relaying to the transmission and distribution systems, and is currently responsible
for managing compliance to NERC Standards for the "wires" portion of Consumers Energy.
He chaired the NERC System Protection and Control Task Force from its inception in 2004
through May 2008, and continues to be a member of its successor group, the NERC System
Protection and Control Task Force. He chaired the ECAR investigation into the August
2003 blackout, chaired the ECAR Protection Panel for several years, and now chairs the
RFC Protection Subcommittee. At NERC, he was a member of the "Phase II Standard
Drafting Team" in 2005-2006, chaired the standard drafting team that developed PRC-0231, and currently chairs the standard drafting teams assigned to Projects 2007-17 (Protection
System maintenance) and 2010-13 (addressing FERC Order 733). At RFC, he also chaired
the standard drafting team that developed PRC-002-RFC-01 and currently chairs a standard
drafting team that is developing a regional standard addressing Special Protection Systems.
Charles is also a member of IEEE Standards Coordinating Committee 21, and was a key
member of the working groups that developed IEEE 1547, IEEE 1547.2, and IEEE 1547.4.
He received his BSEE degree from Michigan Technological University in 1978. He is a
registered professional engineer in the State of Michigan, and is a Senior Member of IEEE.
Dr. Baj L. Agrawal: Ph.D., University of Arizona, Tucson. Dr. Agrawal is Engineering
Manager at Arizona Public Service Co., where he has worked since 1974. He has extensive
experience in the analysis, control and testing of subsynchronous resonance, power system
dynamics modeling and simulation, and field testing of generators. He has co-authored
many papers on subsynchronous resonance analysis and power system testing and has coauthored a book on subsynchronous resonance. Dr. Agrawal is an IEEE fellow and is a
registered professional engineer.

David is the Manager of Delivery Planning for Idaho Power and an Adjunct Professor at
Boise State University. He graduated from the University of Idaho with a Bachelor of
Science degree in electrical engineering in 1984 and followed with a Master of Science
degree in 1986. He has twenty five years of experience in communications, metering,
planning, and system protection with Idaho Power and the Bonneville Power
Administration.

Gary Brownfield is the Supervising Engineer for the Transmission Planning group at
Ameren. He has 36 years of engineering experience in the electric utility industry. His
work experience encompasses transmission expansion planning, NERC standards
compliance, generator interconnection planning, reactive planning, distribution planning,
FIDVR, transient stability, events analyses, lightning and switching surges, power system
harmonics, power quality, geomagnetic disturbances, and system optimization. He
presently serves on the NERC Transmission Issues Subcommittee and the SERC
Engineering Committee. He received BSEE and MSEE degrees from the University of
Missouri. He is a registered professional engineer and is a Senior Member of IEEE.

Larry Brusseau
Principal
Engineer/Compliance Program
Manager
MAPPCOR
1970 Oakcrest Ave.
Suite 200
Roseville, MN 55113
(651)294-7077
Le.brusseau@mappcor.org

W. Mark Carpenter
VP and Chief Technology
Officer
Oncor
2509 Douglas Avenue
Irving, Texas 75062
(214) 486-3588
mark.carpenter@
oncor.com

Jay Caspary
Director, Transmission
Development
Southwest Power Pool
415 North McKinley
Suite 400
Little Rock, AR 72205
(501) 614-3220
jcaspary@spp.org

Mr. Brusseau has over 20 years of experience in the electric power industry. Mr. Brusseau
joined MAPPCOR staff in January, 2009 and currently holds the position of Principal
Engineer. He is the Compliance Program Manager for MAPPCOR and secretary to the MidContinent Compliance Forum. He is also responsible for the Transmission Reliability
Assessment Working Group, Northern MAPP Operating Review Working Group and the
Missouri Basin Subregional Planning Group; which produces the annual MAPP System
Performance Assessment, MAPP Member Reliability Criteria and Study Procedures
Manual, and provides input to the MAPP Regional Transmission Plan. He is a subject matter
expert for MAPPCOR in transmission planning activities, and regional reliability standards,
compliance and enforcement. Prior to joining MAPPCOR, Mr. Brusseau was Midwest
Reliability Organization's Standards Manager. In this role, Mr. Brusseau was responsible
for assuring that the standards process was being followed properly and those standards in
development increased reliability for the region, and was also responsible for the MRO
Compliance Data Management System (CDMS) and the Reliability Standard Voting Process
(RSVP) systems, he worked with MRO's Standards Committee, NERC Standards Review
Subcommittee, Regional Standards Drafting Teams, and NERC Standards Drafting Teams.
He has participated in over 50 Compliance Audits and Readiness Evaluations. From 1989 2005 he worked for MAPP producing the annual MAPP Operating and Planning Stability
model, overseeing the production of the MAPP Operating and Planning Power Flow models,
and was responsible for maintaining MAPP's Model Building Process. He also conducted
transient, voltage and small signal stability studies of the MAPP system as well as other
special studies involving system security. He was chair of NERC's Multiregional Modeling
Working Group (MMWG) and System Dynamics Database Working Group (SDDWG).
Mr. Brusseau received a BSEE degree from North Dakota State University in 1989 and is a
member of the IEEE Power & Energy Society.
Mark joined Texas Power and Light Company as a summer engineering intern in 1972 and
became a permanent employee in 1975 upon completion of his BS Electrical Engineering
degree from Texas Technological University. Mark has held various field management and
engineering management positions in T&D, primarily in the transmission and substation
area of Oncor and its predecessor companies. These include Distribution Superintendent,
Transmission Superintendent, Substation Engineering Manager, Director of System
Protection, Director of Engineering, and Vice President and Chief Information Officer.
Mark is currently serving as Vice President and Chief Technology Officer. In this role, he
leads Oncor’s technology vision, strategic planning, R&D efforts, and technology
implementation. Mark’s protective relaying background is extensive and includes active
participation in the IEEE Power System Relaying Committee as the past Line Protection
Subcommittee Chair and Working Group Chair for the original version of the Transmission
Line Protection Guide and the Guide for Transmission Protective Relaying Performance
Measuring Methodology that formed the basis for system protection performance
measurements. He is a member of the Texas Society of Professional Engineers and is a
registered Professional Engineer in the State of Texas.
As Director of Transmission Development at Southwest Power Pool, Jay is charged with
addressing emerging, strategic and ongoing transmission issues with a primary focus on
removing barriers to effective coordinated expansion planning beyond traditional seams.
Recent initiatives to get the best lines in the best corridors include investigations into
mechanisms and incentives to enable rightsizing key facilities in critical ROWs with due
consideration of land use and environmental impacts. Jay has almost 30 years of experience
in transmission planning, electric and gas resource planning, regulatory services/pricing,
marketing/customer choice, and transmission services.
Jay joined SPP in 2001 after a 19-year career at Illinois Power/Dynegy. Jay has been
instrumental in developing effective transmission expansion plans for SPP, as well as
collaborative long-range planning with SPP’s neighbors including ERCOT, MISO, TVA,
and others. Jay has and continues to serve on several industry committees including NERC’s
Intermittent and Variable Generation Task Force, EPRI’s Grid Operations, Planning &
Renewable Integration program and the DOE’s Eastern Interconnection Planning
Collaborative. Jay has served on the Board of Directors of the Utility Wind Integration
Group since 2006.
Jay graduated from the University of Illinois-Urbana with a Bachelor of Science degree in
Electrical Engineering and has completed course requirements for a Master of Engineering
Degree from Iowa State University.

Kenneth A. Donohoo P.E.
Oncor Electric Delivery
Company LLC
2233 B Mountain Creek
Parkway
Dallas, TX 75211
(214)743-6823
kdonoho1@oncor.com

Jim Griffith
Manager, System Operations
Southern Company Services
P.O. Box 2641
Birmingham, AL 35202
(205) 257-6892
jsgriffi@southernco.com

Ken Donohoo joined Oncor Electric Delivery in May 2007 as Director System Planning.
His team administers distribution and transmission planning analysis including steady state,
dynamic analysis (voltage and transient), harmonic analysis, generation interconnection or
change request studies, NERC support/reporting, regulatory support, planning reports and
collection/development of power system planning data.
Ken has 28 years of related experience in increasingly complex supervisory/management
positions, including significant experience in transmission planning analysis, system
operations and resource planning.
He received a Bachelor of Science Electrical Engineering (BSEE) degree from the
University of Texas at Arlington in 1982. His extensive background includes engineering
budget analysis, transmission planning, transient analysis, EMTP analysis, insulation
coordination, surge arrester application, switching analysis, wheeling impact, loss analysis,
project management, and engineering management.
He is a registered professional engineer in the state of Texas. He is a senior member of
Institute of Electrical and Electronics Engineers (IEEE), active in the Utility Wind
Integration Group (UWIG), serves on the North American Electric Reliability Council
Planning Committee Transmission Issues Subcommittee (TIS), active in the ERCOT
Regional Planning Group and is Chairperson of the ERCOT TAC Reliability Operating
Subcommittee.
Jim Griffith has over 38 years experience at Southern Company. He has worked in power
system (PMS) management application development, operations planning, real time
operations both at the transmission switching level and the Bulk Power Operations level.
These include managing application development groups in the Southern Company PMS
application department which were responsible for developing and installing System
Control, System Security, and Operations Planning applications (AGC, State Estimation,
Unit commitment, etc.) for Southern Company. From there Jim moved to manage the
Operations Planning section for the Bulk Power Operations Power Coordination Center for
Southern Company. He later moved to Alabama Power Company Transmission Control
Center where he was responsible for operations planning and operator training. Jim
currently is manager of real time system operations at the Bulk Power Operations Power
Coordination Center (PCC) for Southern Company. The PCC is responsible for the
generation and load balancing for the Southern Control Area, for interchange scheduling,
and for transmission security, including the Security Coordinator function. Jim has served
in numerous roles in the power industry throughout his career. He has held numerous
positions in NERC and SERC with responsibilities such as: leading the Security Process
Support Systems Task Force, serving on the IDC Working group, the Functional Model
Working Group, as well as various tagging committees and special project committees. He
has represented various entities on the NERC OC such as being the Investor – Owned
Utility group, SERC region representative, etc.
Jim has been on the NERC region SERC Operating Committee for over twelve years
representing Southern Company and serving as vice chair and chair as well as leading other
SERC subcommittees to accomplish specific tasks.

Bill Harm
Sr. Consultant
PJM
HARM@pjm.com
Jim Ingleson
Senior Power System Engineer
RLC Engineering LLC
402 Bond Road
Altamont, NY 12009
518-861-6269
jim.ingleson@rlc-eng.com

Jim has a BS degree from Mississippi State University.
Bill Harm has over 35 years of industry experience with PJM through various assignments
involving real time operation, operations planning, and transmission planning. Mr. Harm’s
current responsibilities involve performance assessment, and policy development
responsibilities. He either has or continues to represent PJM in various industry forums and
groups, including RFC, NERC, and the ISO/RTO forums. He earned a Bachelor and Maters
of Science Degree in Electrical Engineering from Drexel University and is a registered
professional Engineer Commonwealth of Pa.
Jim Ingleson is a Senior Power System Engineer with RLC Engineering LLC, specializing
in system protection. Previously Jim has worked for General Electric Company, New York
Power Pool, and New York ISO. He received the 2007 IEEE PES Distinguished Service
Award for career service to the Power System Relay Committee, and is a past Chair of the
NPCC Task Force on System Protection. Jim holds B.S. and M. Eng. Degrees in Electric
Power Engineering from RPI. His years of service to the electric utility industry total over
42. Mr. Ingleson is a licensed Professional Engineer in MA and NY, and a Senior Member
of the IEEE.

Takis Laios
Manager Projects
American Electric Power
700 Morrison Road
Gahanna, OH 43230-6642
(614) 552-1664
tlaios@aep.com
John Odom
Vice President of Planning and
Operations
Florida Reliability
Coordinating Council, Inc.
1408 N. Westshore Blvd.,
Suite 1002
Tampa, FL 33607-4512
(813)207-7985
jodom@frcc.com
Chifong Thomas
Senior Director, Energy
Market and Strategy
BrightSource Energy, Inc.
1999 Harrison Street
Suite 2150
Oakland, CA 94612
(510) 250-8166
cthomas@
brightsourceenergy.com

Dana Walters
Mgr Transmission Planning,
Process & Policy
nationalgrid
40 Sylvan Road,
Waltham, MA 02451
781-907-2501
dana.walters@us.ngrid.com
Philip B. Winston
Chief Engineer
Southern Company
Transmission
62 Like Mirror Road
Bin # 50061
Forest Park, Georgia 30297
(404) 608-5989
pbwinsto@southernco.com

Takis Laios has over 30 years of industry experience with AEP through various assignments
involving transmission planning, performance assessment, and policy development
responsibilities. He either has or continues to represent AEP in various industry forums and
groups, including ECAR, RFC, NERC, and PJM. He earned a Bachelor of Science Degree
in Electrical Engineering from Northeastern University, a Master of Engineering Degree in
Electric Power Engineering from Rensselaer Polytechnic Institute, and a Masters in
Business Administration Degree from The Ohio State University.

John Odom is Vice President of Planning and Operations at the Florida Reliability
Coordinating Council (FRCC). John joined FRCC in May, 2005 after 26 years at Progress
Energy Corporation (PEF). He is responsible for oversight of all Member Services
Activities, including the FRCC standing committees, FRCC Reliability Coordinator and
Planning Authority function. Additionally, he oversees the Regional Entity functions of
reliability assessment, situational awareness, training and certification of system operators,
and event analysis. From 2001 – 2007, John was the FRCC Representative on the NERC
Reliability Assessment Subcommittee (RAS). John is currently the chair of the Assess
Future Transmission Needs Standards Drafting Team (AFTNSDT), which is re-writing the
existing TPL-001 through TPL-006.

Chifong Thomas is the Senior Director, Energy Markets and Strategy at BrightSource
Energy, Inc. Prior to her current position, she was a Principal Transmission Planning
Engineer at Pacific Gas and Electric Company (PG&E). She has more than 39 years of
electric utility experience, more than 37 of which in electric transmission planning. She has
both conducted and supervised transmission planning studies to develop plans for PG&E
transmission system from 60 kV to 500 kV. She has participated in developing
methodologies, policies and strategic plans, and in contract negotiations. Ms Thomas has
also served as expert witness in various regulatory and judicial forums. She has served on
various technical organizations and work groups, including WECC Technical Studies
Subcommittee (where she served as Chair from 2003 to 2005) and various WECC task
forces, four NERC Standards Drafting Teams, and Industry Advisory Committees of the
California Energy Commission and of EPRI. She currently serves as Secretary of the
WECC-Planning Coordination Committee (PCC) and also chairs the WECC PCC-TEPPC
Coordination Task Force. She had also served on the Technical Advisory Committee
(Electrical Engineering) to California Board of Registration for Professional Engineers and
Land Surveyors. Ms Thomas holds a Bachelor of Science Degree in Electrical Engineering
from Washington State University and is a registered Electrical Engineer in the State of
California. She is also a senior member of the IEEE.
Dana Walters is a Manager in the Transmission Planning group at National Grid. Mr.
Walters has 34 year of experience in the Electric Utility industry. Most of his experience
involves various aspects of Transmission Planning. This includes topics such as analytical
studies of thermal, stability, short circuit, generator interconnections, and lightning
protection. Other areas of experience include involvement in Investment Planning, tariff
design, Consulting, Production Cost analysis, and Distribution Planning. In his role as a
Transmission Planner, Mr. Walters has been involved in numerous committees and working
groups at the NERC, NPCC, and ISO levels. Mr. Walters has a Masters in Engineering
Management from Northeastern University and a Bachelor in Electrical Engineering with a
focus in Power Systems also from Northeastern University. Mr. Walters is a registered
professional engineer in New Hampshire and is a member of IEEE.
Philip Winston is presently the Chief Engineer, Protection and Control for Southern
Company Transmission. Previously he was the Manager, Protection and Control
Applications with Georgia Power Company for 20 years. With over 37 years experience in
Protection, Operations, and Engineering, he is active in Southern Company standardization
efforts as well as being involved in regional and national organizations responsible for
utility standards and disturbance analysis. He is the past Chairman of the IEEE/ Power
System Relaying Committee and past Chair of the PSRC Systems Protection and the Line
Protection Subcommittees. He serves on the NERC SPCS, and several NERC Standard
Drafting Teams. He holds a BSEE from Clemson University, a MSEE from Georgia Tech,
and is a registered Professional Engineer in the State of Georgia.

Eric Allen
North American Electric
Reliability Corporation
116-390 Village Boulevard
Princeton, New Jersey 085405721
Eric.Allen@nerc.net
Joseph Bucciero
President and Executive
Consultant
NERC Coordinator
Bucciero Consulting, LLC
3011 Samantha Way
Gilbertsville, Pennsylvania
19525
(267) 981-5445
joe.bucciero@gmail.com

Robert W. Cummings
Director of System Analysis
and Reliability Initiatives
NERC Staff Liaison &
Subject Matter Expert
North American Electric
Reliability Corporation
116-390 Village Boulevard
Princeton, New Jersey 085405721
(609) 947-0103
(505) 508-1198
bob.cummings@nerc.net

Philip J Tatro
Senior Performance and
Analysis Engineer
NERC Staff Advisor &
Subject Matter Expert
North American Electric
Reliability Corporation
116-390 Village Boulevard
Princeton, New Jersey 085405721
(609) 452-8060
phil.tatro@nerc.net

Eric Allen received his B.S. degree in Electrical Engineering from Worcester Polytechnic
Institute in 1993 and his S.M. degree in Electrical Engineering from the Massachusetts
Institute of Technology in 1995. In 1998 he received the Ph.D. degree in Electrical
Engineering from M.I.T. with the thesis titled “Stochastic Unit Commitment in a
Deregulated Electric Utility Industry.” Eric was employed for more than 7 years as a Senior
Engineer in transmission planning at the New York Independent System Operator (NYISO),
and is now employed as a Senior Engineer in System Analysis and Reliability Initiatives at
the North American Electric Reliability Council (NERC). He has participated extensively in
the investigation of the August 14, 2003 blackout. He is a licensed Professional Engineer in
New York and participates in the IEEE Power System Dynamic Performance Committee.
Joseph (Joe) Bucciero is the NERC Staff Coordinator for the Relay Loadability Order 733
Drafting Team and the Cyber Security Order 706 Drafting Team. Mr. Bucciero is an
electric industry executive with more than 40 years of industry experience that has
successfully established his position and reputation as a leader in the industry. He has
extensive management, technical, and business development experience in serving the needs
of the electric utilities. He has launched his own practice to provide strategic guidance on
Smart Grid, interoperability, cyber security, and EMS/SCADA issues to utilities, vendors,
and industry groups. He is skilled in project management, and is adept at developing
innovative, cost-effective ideas and solutions, and providing engineering and real-time
system services that support utility corporate objectives. Mr. Bucciero is a council emeritus
member on the US DoE “GridWise Architecture Council”, a signatory of the GridWise
Interoperability Constitution, and a member of the Cigré Working Group on 21st Century
EMS Architectures. He is a founding Board Member of the Institute of Research and
Education in Power System Dynamics (IREP), is a Senior Member of IEEE, and holds BSc
Mathematics from Villanova University.
Mr. Cummings joined NERC in 1996 and has extensive experience in the industry in system
planning, operations engineering, and wide area planning. He holds a Bachelor of Science
Degree in Power System Engineering from Worcester Polytechnic Institute and is an IEEE
Senior Member.
His geographically diverse experience includes Central Vermont Public Service Corporation
in System Planning (generation and transmission), Public Service Company of New Mexico,
and the East Central Reliability Coordination Agreement (ECAR).
Mr. Cummings was the “father” of power interchange transaction “tagging” and the
Interchange Distribution Calculator, which shows loading contributions on key system
transmission interfaces, or “flowgates,” for the Eastern Interconnection.
He was intimately involved in the investigation team of the 2003 blackout as a team leader
with responsibilities in the sequence of events development, modeling and studies
(powerflow and dynamics analysis), and transmission/generation performance areas. He
directed the NERC Event Analysis and Information Exchange program for five years.
Mr. Cummings was instrumental in the founding of the NERC System Protection and
Controls Task Force, now the System Protection and Control Subcommittee (SPCS), acting
as the staff coordinator from 2004 through 2009.
Mr. Cummings is the staff coordinator for the NERC Transmission Issues Subcommittee
and is the technical advocate in the North American Synchro-Phasor Initiative. He is also
the technical director of the NERC System Protection and Control Performance
Improvement Initiative, the Modeling Improvements Initiative, and the Frequency Response
Improvement Initiative.
Phil Tatro is the NERC staff coordinator for the System Protection Control Subcommittee
(SPCS) and has 25 years of industry experience. Prior to joining NERC he worked for 23
years at New England Electric System and National Grid. His experience there included
assignments in Protection and Control Engineering, the Québec-New England 2000 MW
HVdc interconnection, development of independent transmission projects, and Transmission
Planning. During this time he was a member of several NERC, NPCC and New England
Power Pool committees, task forces, and standard drafting teams. Phil chaired the NPCC
SS-38 Working Group on Inter-Area Dynamic Analysis and the NERC Major System
Disturbance Task Force responsible for dynamic simulation of the August 14, 2003
blackout. He received his Bachelor of Science degree, magna cum laude, from Rensselaer
Polytechnic Institute in Troy, NY in 1985 and his Master of Engineering degree, also from
Rensselaer Polytechnic Institute, in 1986. He is a registered professional engineer in the
Commonwealth of Massachusetts and is a member of the IEEE Power & Energy Society.

Exhibit D
Mapping Document for the proposed PRC-023-2 Reliability Standard

PRC-023-2 Mapping of Requirements from PRC-023-1 and
Directed Modifications in Order No. 733
Mapping of PRC-023-1 to PRC-023-2
Requirement in the Existing PRC-023-1

Location in
PRC-023-2

R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall use
any one of the following criteria (R1.1 through R1.13) for any specific circuit terminal
to prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the Bulk Electric System for all fault
conditions. Each Transmission Owner, Generator Owner, and Distribution Provider
shall evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30
degrees:

Requirement
R1

R1.1. Set transmission line relays so they do not operate at or below 150% of the
highest seasonal Facility Rating of a circuit, for the available defined loading duration
nearest 4 hours (expressed in amperes).
R1.2. Set transmission line relays so they do not operate at or below 115% of the
highest seasonal 15-minute Facility Rating2 of a circuit (expressed in amperes).
R1.3. Set transmission line relays so they do not operate at or below 115% of the
maximum theoretical power transfer capability (using a 90-degree angle between the
sending end and receiving-end voltages and either reactance or complex impedance)
of the circuit (expressed in amperes) using one of the following to perform the power
transfer calculation:
R1.3.1. An infinite source (zero source impedance) with a 1.00 per unit bus voltage
at each end of the line.
R1.3.2. An impedance at each end of the line, which reflects the actual system
source impedance with a 1.05 per unit voltage behind each source impedance.
R1.4. Set transmission line relays on series compensated transmission lines so they do
not operate at or below the maximum power transfer capability of the line,
determined as the greater of:
- 115% of the highest emergency rating of the series capacitor.
- 115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with R1.3, using the full line inductive
reactance.
R1.5. Set transmission line relays on weak source systems so they do not operate at or
below 170% of the maximum end-of-line three-phase fault magnitude (expressed in
amperes).
R1.6. Set transmission line relays applied on transmission lines connected to
generation stations remote to load so they do not operate at or below 230% of the
aggregated generation nameplate capability.
R1.7. Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current

Requirements
R1.1 through
R1.13 are now
criteria 1
through 13
under
Requirement
R1

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of PRC-023-1 to PRC-023-2
Requirement in the Existing PRC-023-1

Location in
PRC-023-2

flow from the load to the generation source under any system configuration.
R1.8. Set transmission line relays applied on the bulk system-end of transmission lines
that serve load remote to the system so they do not operate at or below 115% of the
maximum current flow from the system to the load under any system configuration.
R1.9. Set transmission line relays applied on the load-end of transmission lines that
serve load remote to the bulk system so they do not operate at or below 115% of the
maximum current flow from the load to the system under any system configuration.
R1.10. Set transformer fault protection relays and transmission line relays on
transmission lines terminated only with a transformer so that they do not operate at
or below the greater of:
- 150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.
- 115% of the highest operator established emergency transformer rating.
R1.11. For transformer overload protection relays that do not comply with R1.10 set
the relays according to one of the following:
- Set the relays to allow the transformer to be operated at an overload level of at
least 150% of the maximum applicable nameplate rating, or 115% of the highest
operator established emergency transformer rating, whichever is greater. The
protection must allow this overload for at least 15 minutes to allow for the
operator to take controlled action to relieve the overload.
- Install supervision for the relays using either a top oil or simulated winding hot
spot temperature element. The setting should be no less than 100° C for the top
oil or 140° C for the winding hot spot temperature3.
R1.12. When the desired transmission line capability is limited by the requirement to
adequately protect the transmission line, set the transmission line distance relays to a
maximum of 125% of the apparent impedance (at the impedance angle of the
transmission line) subject to the following constraints:
R1.12.1. Set the maximum torque angle (MTA) to 90 degrees or the highest
supported by the manufacturer.
R1.12.2. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per
unit voltage and a power factor angle of 30 degrees.
R1.12.3. Include a relay setting component of 87% of the current calculated in
R1.12.2 in the Facility Rating determination for the circuit.
R1.13. Where other situations present practical limitations on circuit capability, set the
phase protection relays so they do not operate at or below 115% of such limitations.
R2. The Transmission Owner, Generator Owner, or Distribution Provider that uses a
circuit capability with the practical limitations described in R1.6, R1.7, R1.8, R1.9,
R1.12, or R1.13 shall use the calculated circuit capability as the Facility Rating of the
circuit and shall obtain the agreement of the Planning Coordinator, Transmission
Operator, and Reliability Coordinator with the calculated circuit capability.

Requirement
R3

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of PRC-023-1 to PRC-023-2
Requirement in the Existing PRC-023-1

Location in
PRC-023-2

R3. The Planning Coordinator shall determine which of the facilities (transmission lines
operated at 100 kV to 200 kV and transformers with low voltage terminals connected
at 100 kV to 200 kV) in its Planning Coordinator Area are critical to the reliability of the
Bulk Electric System to identify the facilities from 100 kV to 200 kV that must meet
Requirement 1 to prevent potential cascade tripping that may occur when protective
relay settings limit transmission loadability.

Requirement
R6

R3.1. The Planning Coordinator shall have a process to determine the facilities that are
critical to the reliability of the Bulk Electric System.
R3.1.1. This process shall consider input from adjoining Planning Coordinators and
affected Reliability Coordinators.

Attachment B

R3.2. The Planning Coordinator shall maintain a current list of facilities determined
according to the process described in R3.1.

Requirement
R6, Part 6.1

R3.3. The Planning Coordinator shall provide a list of facilities to its Reliability
Coordinators, Transmission Owners, Generator Owners, and Distribution Providers
within 30 days of the establishment of the initial list and within 30 days of any changes
to the list.

Requirement
R6, Part 6.2

Mapping of Directed Changes in Order No. 733
Paragraph in
Order No. 733

Text

Location in
PRC-023-2

With respect to sub-100 kV facilities, we adopt the NOPR proposal
and direct the ERO to modify PRC-023-1 to apply an “add in”
approach to sub-100 kV facilities that are owned or operated by
currently-Registered Entities or entities that become Registered
Entities in the future, and are associated with a facility that is
included on a critical facilities list defined by the Regional Entity.
We also direct that additions to the Regional Entities’ critical facility
list be tested for their applicability to PRC-023-1 and made subject
to the Reliability Standard as appropriate.

Requirement R6
and Attachment
B

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of Directed Changes in Order No. 733
Paragraph in
Order No. 733

Text

Location in
PRC-023-2

System. We direct the ERO to file its test, and the results of
applying the test to a representative sample of utilities from each
of the three Interconnections, for Commission approval no later
than one year from the date of this Final Rule.
97

Finally, commenters argue that there should be some mechanism
for entities to challenge criticality determinations. We agree that
such a mechanism is appropriate and direct the ERO to develop an
appeals process (or point to a process in its existing procedures)
and submit it to the Commission no later than one year after the
date of this Final Rule.

Addressed in
Section 1700 of
the NERC Rules
of Procedure

186

However, we will adopt the NOPR proposal to direct the ERO to
modify PRC-023-1 to require that transmission owners, generator
owners, and distribution providers give their transmission
operators a list of transmission facilities that implement subrequirement R1.2.

Requirement R4

203

We adopt the NOPR proposal and direct the ERO to modify subrequirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated
overload for the longest clearing time associated with the fault.

Requirement R1,
criterion 10, Part
10.1

224

While we are not adopting the NOPR proposal, we direct the ERO
to document, subject to audit by the Commission, and to make
available for review to users, owners and operators of the BulkPower System, by request, a list of those facilities that have
protective relays set pursuant sub-requirement R1.12.

Requirement R5
provides the
ERO the data
necessary to
make available
the list of
facilities

237

We adopt the NOPR proposal and direct the ERO to modify the
Reliability Standard to add the Regional Entity to the list of entities
that receive the critical facilities list. [sub-requirement R3.3]

Requirement R6,
Part 6.2

244

We adopt the NOPR proposal and direct the ERO to include section
2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor
and violation severity level.

Requirement R2

264

After further consideration, and in light of the comments, we will

Attachment A,

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of Directed Changes in Order No. 733
Paragraph in
Order No. 733

Text

Location in
PRC-023-2

not direct the ERO to remove any exclusion from section 3, except
for the exclusion of supervising relay elements in section 3.1.
Consequently, we direct the ERO to revise section 1 of Attachment
A to include supervising relay elements on the list of relays and
protection systems that are specifically subject to the Reliability
Standard.

Section 1.6 and
Attachment A,
Section 2.1

283

Additionally, in light of our directive to the ERO to expand the
Reliability Standard’s scope to include sub-100 kV facilities that
Regional Entities have already identified as necessary to the
reliability of the Bulk-Power System through inclusion in the
Compliance Registry, we direct the ERO to modify the Reliability
Standard to include an implementation plan for sub-100 kV
facilities.

Implementation
Plan

284

We also direct the ERO to remove the exceptions footnote from
the “Effective Dates” section.

Footnote 1
removed from
the “Effective
Dates: section

Exhibit E
Proposed NERC Rules of Procedure Section 1700 – Challenges to Determinations

PROPOSED NEW SECTION FOR NERC RULES OF PROCEDURE
SECTION 1700 — CHALLENGES TO DETERMINATIONS
1701. Scope of Authority
Section 1700 sets forth the procedures to be followed for Registered Entities to
challenge determinations made under various Reliability Standards or terms
defined in the Glossary of Terms Used in NERC Reliability Standards.
1702. Challenges to Determinations by Planning Coordinators Under Reliability
Standard PRC-023
1. This Section 1702 establishes the procedures to be followed when a Registered
Entity wishes to challenge a determination by a Planning Coordinator of the
sub-200 kV circuits in its Planning Coordinator area for which Transmission
Owners, Generator Owners, and Distribution Providers (defined as “Registered
Entities” for purposes of this Section 1702) must comply with the requirements
of Reliability Standard PRC-023.
2. Planning Coordinator Procedures
2.1

2.2

2.3

Each Planning Coordinator shall establish a procedure for a
Registered Entity to submit a written request for an explanation of
a determination made by the Planning Coordinator under PRC023.
A Registered Entity shall follow the procedure established by the
Planning Coordinator for submitting the request for explanation
and must submit any such request within 60 days of receiving the
determination under PRC-023 from the Planning Coordinator.
Within 30 days of receiving a written request from a Registered
Entity, the Planning Coordinator shall provide the Registered
Entity with a written explanation of the basis for its determination
under PRC-023, unless the Planning Coordinator provided a
written explanation of the basis for its determination when it
initially informed the Registered Entity of its determination.

3. A Registered Entity may challenge the determination of the Planning
Coordinator by filing with the appropriate Regional Entity, with a copy to the
Planning Coordinator, within 60 days of receiving the written explanation from
the Planning Coordinator. The challenge shall include the following: (a) an
explanation of the technical reasons for its disagreement with the Planning
Coordinator’s determination, along with any supporting documentation, and (b)
a copy of the Planning Coordinator’s written explanation. Within 30 days of
receipt of a challenge, the Planning Coordinator may file a response to the
Regional Entity, with a copy to the Registered Entity.
1

4. The filing of a challenge in good faith shall toll the time period for
compliance with PRC-023 with respect to the subject facility until such time
as the challenge is withdrawn, settled or resolved.
5. The Regional Entity shall issue its written decision setting forth the basis of
its determination within 90 days after it receives the challenge and send
copies of the decision to the Registered Entity and the Planning Coordinator.
The Regional Entity may convene a meeting of the involved entities and may
request additional information. The Regional Entity shall affirm the
determination of the Planning Coordinator if it is supported by substantial
evidence.
6. A Planning Coordinator or Registered Entity affected by the decision of the
Regional Entity may, within 30 days of the decision, file an appeal with
NERC, with copies to the Regional Entity and the Planning Coordinator or
Registered Entity. The appeal shall state the basis of the objection to the
decision of the Regional Entity and shall include the Regional Entity
decision, the written explanation of the Planning Coordinator’s determination
under PRC-023, and the documents and reasoning filed by the Registered
Entity with the Regional Entity in support of its objection. The Regional
Entity, Planning Coordinator or Registered Entity may file a response to the
appeal within 30 days of the appeal.
7.

The NERC Board of Trustees shall appoint a panel to decide appeals from
Region Entity decisions under Section 1702.5. The panel, which may
contain alternates, shall consist of at least three appointees, one of whom
must be a member of the NERC staff, who are knowledgeable about PRC023 and transmission planning and do not have a direct financial or business
interest in the outcome of the appeal. The panel shall decide the appeal
within 90 days of receiving the appeal from the decision of the Regional
Entity and shall affirm the determination of the Planning Coordinator if it is
supported by substantial evidence.

8. The Planning Coordinator or Registered Entity affected by the decision of the
panel may request that the NERC Board of Trustees review the decision by
filing its request for review and a statement of reasons with NERC’s Chief
Reliability Officer within 30 days of the panel decision. The Board of
Trustees may, in its discretion, decline to review the decision of the panel, in
which case the decision of the panel shall be the final NERC decision. Within
90 days of the request for review under this Section 1702.8, the NERC Board
of Trustees may either: (a) issue a decision on the merits, which shall be the
final NERC decision, or (b) issue a notice declining to review the decision of
the panel, in which case the decision of the panel shall be the final NERC
decision. If no written decision or notice declining review is issued within 90
calendar days, the appeal shall be deemed to have been denied by the NERC
2

Board of Trustees and this will have the same effect as a notice declining
review.
9. The Registered Entity or Planning may appeal the final NERC decision to the
applicable governmental authority within 30 days of receipt of the Board of
Trustees’ final decision or notice declining review, or expiration of the 90day review period without any action by NERC. .
10. The Planning Coordinator and Registered Entity are encouraged, but not
required, to meet to resolve any dispute, including use of mutually agreed to
alternative dispute resolution procedures, at any time during the course of the
matter. In the event resolution occurs after the filing of a challenge, the
Registered Entity and Planning Coordinator shall jointly provide to the
applicable Regional Entity a written acknowledgement of withdrawal of the
challenge or appeal, including a statement that all outstanding issues have
been resolved.

Exhibit F
Development Record of the proposed PRC-023-2 Reliability Standard

Project 2010-13: Relay Loadability Order
Related Files

Status:

The NERC Board of Trustees adopted the standard and implementation plan and approved the VRFs
and VSLs at its March 10, 2011 meeting.
Background:
As the ERO, NERC must address all directives in Orders issued by FERC. On March 18, 2010
FERC issued Order No. 733 which approved Reliability Standard PRC-023-1 – Transmission
Relay Loadability, and also directed NERC, as the Electric Reliability Organization (“ERO”), to
develop certain modifications to the PRC-023-1 standard through its Reliability Standards
development process, to be completed by specific deadlines. Attachment 1 to the SAR contains
the directives and associated deadlines. The Order also directed development of two new
Reliability Standards to address issues related to generator relay loadability and the operation of
protective relays due to power swings. The standards-related directives in Order 733 are aimed
at closing some reliability-related gaps in the scope of PRC-023-1.
This SAR’s scope includes three standard development phases to address the standards-related
directives in Order No. 733 directives. Phase I is focused on making the specific modifications to
PRC-023-1 that were identified in the order; Phase II is focused on developing a new standard
to address generator relay loadability; and Phase III is focused on developing requirements that
address protective relay operations due to power swings.

Draft

Action

Dates

Results

Consideration of
Comments

Draft PRC-023-2
Clean (44)| Redline to last
posting(45)
Redline to last approval(46)
Implementation Plan
Clean(42) | Redline to last
posting(43)

PRC-023-2
Clean (32)| Redline to last
posting(33)
Redline to last approval(34)

Recirculation
Ballot
Info(47)
Vote>>

Successive
Ballot
Info(38)
Vote>>

Implementation Plan
Clean (30)| Redline to last

Summary(49)
02/24/11
- 03/07/11

01/24/11
02/14/11

Full
Record(48)

Consideration of
Comments

Summary(40)
Consideration of
Comments(41)
Full
Record(39)

posting(31)

Supporting Materials

Non-Binding
Poll
Info(35)

01/24/11
02/13/11

Vote>>

Non-Binding
Poll
Results(36)

Consideration of
Comments(37)

VRF/VSL Justification(29)
Mapping Document(28)

Intial Ballot
Info(24)
Vote>>
SAR for Relay Loadability
clean (18)| Redline to last
posting(19)

Info(23)

Join>>

Implementation Plan
Clean(14)

45-day Formal

Supporting Materials:

Comment
Period
Info(20)
Submit
Comments>>

PRC-023- Attachment B(9)
Supporting Materials:
Comment form (Word)(8)

Summary(26)
Full
Record(25)

Consideration of
Comments(27)

Ballot Pool

PRC-023-2
Clean (15)| Redline to last
posting(16)
Redline to last approval(17)

Comment form (Word)(13)

12/07/10
12/16/10
(closed)

11/01/10
12/02/10
(closed)

11/01/10
–
12/16/10
(closed)

Comments
Received(21)

Consideration of
Comment(22)

9/23/10 10/12/10
(closed)

Comments
Received(11)

Consideration of
Comments (12)

08/19/10
09/19/10
(closed)

Comments
Received(6)

Consideration of
Comments (7)

Comment
Period
Info(10)
Submit
Comments>>

Draft 1
SAR for Relay Loadability
Modifications and Additions
PRC-023-2
Draft SAR Version 1 (4)

Comment
Period
Info>>(5)

Supporting Materials:
Comment Form (Word)(3)

Submit
Comments>>

PRC-023-2
clean (1)| redline (2)to last
approval

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Anticipated Date

1. Develop second draft of SAR and respond to comments.

September, 2010 –
October, 2010

2. Post the standard for 45-day comment period with concurrent
ballot

October , 2010

3. Develop second draft of the standard and respond to comments.

December, 2010 –
January, 2011

4. Re-ballot the proposed standard

January, 2011

5. NERC Board approval

February, 2011

6. Submit standard to FERC for approval

March, 2011

Approved by Board of Trustees: TBD

Standard PRC-023-2 — Transmission Relay Loadability

A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-2

The SDT will ensure that
4.1.2 and 4.1.4 are
consistent with the
applicability methodology
once it is developed.

4.2. Generator Owners with load-responsive phase protection systems as described in
Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.
4.3. Distribution Providers with load-responsive phase protection systems as described in
Attachment A, applied according to facilities defined in 4.1.1 through 4.1.4., provided that
those facilities have bi-directional flow capabilities.
4.4. Planning Coordinators.
5. Effective Dates:
5.1. Requirement R1, Requirement R2, Requirement R3, Requirement R4:
5.1.1 For circuits described in 4.1.1 and 4.1.3 above (except for switch-on-to-fault
schemes) —the beginning of the first calendar quarter following applicable
regulatory approvals.
5.1.2 For circuits described in 4.1.2 and 4.1.4 above (including switch-on-to-fault
schemes) — at the beginning of the first calendar quarter 39 months following
applicable regulatory approvals.
5.1.3 Each Transmission Owner, Generator Owner, and Distribution Provider shall have
24 months after being notified by its Planning Coordinator pursuant to
Requirement R5, Part 5.3 to comply with Requirement R1 (including all subrequirements) for each facility that is added to the Planning Coordinator’s critical
facilities list determined pursuant to Requirement R5, Part 5.1.
5.2. Requirement R5: 18 months following applicable regulatory approvals.

Approved by Board of Trustees: TBD

Standard PRC-023-2 — Transmission Relay Loadability
B. Requirements
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1, Settings1 through 13) for any specific circuit terminal
to prevent its phase protective relay settings from limiting transmission system loadability
while maintaining reliable protection of the BES for all fault conditions, and to prevent its outof-step blocking schemes from blocking tripping for fault conditions. Each Transmission
Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per
unit voltage and a power factor angle of 30 degrees: [Violation Risk Factor: High] [Mitigation
Time Horizon: Long Term Planning].
Settings:
1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal
Facility Rating of a circuit, for the available defined loading duration nearest 4 hours
(expressed in amperes).
2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal
15-minute Facility Rating 1 of a circuit (expressed in amperes).
3. Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:
•

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at
each end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not
operate at or below the maximum power transfer capability of the line, determined as the
greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with Requirement R1, Setting 3, using the full
line inductive reactance.

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Approved by Board of Trustees: TBD

Standard PRC-023-2 — Transmission Relay Loadability
8. Set transmission line relays applied on the bulk system-end of transmission lines that serve
load remote to the system so they do not operate at or below 115% of the maximum current
flow from the system to the load under any system configuration.
9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the to the under any system configuration.
10. Set transformer fault protection relays and transmission
line relays on transmission lines terminated only with a
transformer such that the protection settings do not
expose the limiting piece of equipment to fault level and
duration that exceeds its capability and so that the relays
do not operate at or below the greater of:

FERC Order 733, ¶203:
Modify sub-requirement R1.10
to verify equipment is capable
of sustaining the anticipated
overload associated with the
fault.

•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

•

115% of the highest operator established emergency transformer rating.

11. For transformer overload protection relays that do not comply with Requirement R1,
Setting 10 set the relays according to one of the following:
•

•

12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.
b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
c. Include a relay setting component of 87% of the current calculated in Requirement
R1, Setting 12 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

Each Transmission Owner, Generator Owner, and Distribution Provider that uses a circuit
capability with the practical limitations described in Requirement R1, Settings.6,7, 8, 9, 12, or

IEEE standard C57.115, Table 3, specifies that transformers are to be designed to withstand a winding hot spot
temperature of 180 degrees C, and cautions that bubble formation may occur above 140 degrees C.

Approved by Board of Trustees: TBD

Standard PRC-023-2 — Transmission Relay Loadability
13 shall use the calculated circuit capability as the Facility Rating of the circuit and shall obtain
the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator
with the calculated circuit capability. [Violation Risk Factor: Medium] [Time Horizon: Long
Term Planning]
R3.

FERC Order 733, ¶186: Modify
Each Transmission Owner, Generator Owner, and
R1.2 to require that TOs, GOs,
Distribution Provider that sets transmission line relays
and DPs give their TOPs a list of
according to Requirement R1 Setting 2 shall provide its
transmission facilities that
Planning Coordinator, Transmission Operator, Regional
implement R1.2.
Entity, and Reliability Coordinator with a list of facilities
associated with those transmission line relays at least once each calendar year, with no more
than 15 months between reports [Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]

R4.

Each Transmission Owner, Generator Owner, and
Distribution Provider that sets transmission line relays
according to Requirement R1 Setting 12 shall provide a list
of the facilities associated with those relays to its Regional
Entity at least once each calendar year, with no more than
15 months between reports. [Violation Risk Factor: Lower]
[Time Horizon: Long Term Planning]

R5.

Each Planning Coordinator shall apply the criteria in
Attachment B to determine which of the facilities
(transmission lines operated below 200 kV and transformers with low voltage terminals
connected below 200 kV) in its Planning Coordinator Area are critical to the reliability of the
BES to identify the facilities below 200 kV that must meet Requirement R1 to prevent
cascading when protective relay settings limit transmission loadability. [Violation Risk Factor:
High] [Time Horizon: Long Term Planning]

FERC Order 733, ¶224: Make
available for review to users,
owners and operators of the
Bulk-Power System, by request,
a list of those facilities that have
protective relays set pursuant
sub-requirement R1.12.of
anticipated overload.

5.1

The Planning Coordinator shall have a process to use the criteria established within
Attachment B to determine the facilities that are critical to the reliability of the Bulk
Electric System.

5.2

Each Planning Coordinator shall maintain a current list
of facilities determined according to the process
described in Requirement R5 Part 5.1.

5.3

Each Planning Coordinator shall provide a list of
facilities to its Regional Entity, Reliability
Coordinators, Transmission Owners, Generator Owners,
and Distribution Providers within 30 calendar days of the establishment of the initial
list and within 30 calendar days of any changes to that list.

Approved by Board of Trustees: TBD

FERC Order 733, ¶237:
Modify sub-requirement
R3.3 to add the RE to
list of entities that
receive the critical
facilities list.

Standard PRC-023-2 — Transmission Relay Loadability
PRC-023 — Attachment A
1.

This standard includes any protective functions which could trip with or without time delay, on
load current, including but not limited to:
1.1. Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided protection schemes including but not limited to:
1.5.1 Permissive overreach transfer trip (POTT).
1.5.2 Permissive under-reach transfer trip (PUTT).
1.5.3 Directional comparison blocking (DCB).
1.5.4 Directional comparison unblocking (DCUB).

FERC Order 733, ¶264: Revise
section 1 of Attachment A to
include supervising relay
elements.

1.6. Protective functions that supervise operation of other protective functions in 1.1 through
1.5.
2.

The following protection systems are excluded from requirements of this standard:

2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications.

2.2. Protection systems intended for the detection of ground fault conditions.
2.3. Protection systems intended for protection during stable power swings.
2.4. Generator protection relays that are susceptible to load.
2.5. Relay elements used only for Special Protection Systems applied and approved in
accordance with NERC Reliability Standards PRC-012 through PRC-017 or their
successors.
2.6. Protection systems that are designed only to respond in time periods which allow 15
minutes or greater to respond to overload conditions.
2.7. Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.
2.8. Relay elements associated with dc lines.
2.9. Relay elements associated with dc converter transformers.

Approved by Board of Trustees: TBD

Standard PRC-023-12 — Transmission Relay Loadability
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on August 12, 2010.
2. SAR posted for formal comment on August 19, 2010.
3. Standard posted for informal comment period on August 19, 2010.
Proposed Action Plan and Description of Current Draft:
This is the first draft of the requirements developed to address the FERC directives in Order No. 733 and
posted for an informal comment period.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Develop second draft of SAR and respond to comments.

September, 2010 –
October, 2010

2. Post the standard for 45-day comment period with concurrent
ballot

October , 2010

3. Develop second draft of the standard and respond to comments.

December, 2010 –
January, 2011

4. Re-ballot the proposed standard

January, 2011

5. NERC Board approval

February, 2011

6. Submit standard to FERC for approval

March, 2011

Approved by Board of Trustees: TBD

Standard PRC-023-12 — Transmission Relay Loadability

A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-12

FERC Order 733, ¶60:
Apply an “add in” approach
to sub-100 kV facilities.

4.1.1 Transmission lines operated at 200 kV and above.
4.1.2 Transmission lines operated at below 100 kV to 200 kV as designated by the
Planning Coordinator as critical to the reliability of the
Bulk Electric System
The SDT will ensure that
4.1.3 Transformers with low voltage terminals connected at
200 kV and above.

4.1.2 and 4.1.4 are
consistent with the
applicability methodology
once it is developed.

4.1.4 Transformers with low voltage terminals connected at
below 100 kV to 200 kV as designated by the Planning
Coordinator as critical to the reliability of the Bulk Electric System (BES).
4.2. Generator Owners with load-responsive phase protection systems as described in
Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.

4.3. Distribution Providers with load-responsive phase protection systems as described in
Attachment A, applied according to facilities defined in
4.1.1 through 4.1.4., provided that those facilities have biFERC Order 733, ¶284:
directional flow capabilities.
Remove the exceptions
footnote from the “Effective
Dates” section.

4.4. Planning Coordinators.
5. Effective Dates 1:

5.1. Requirement R1, Requirement R2, Requirement R3, Requirement R4:
5.1.1 For circuits described in 4.1.1 and 4.1.3 above (except for switch-on-to-fault
schemes) —the beginning of the first calendar quarter following applicable
regulatory approvals.
5.1.2 For circuits described in 4.1.2 and 4.1.4 above (including switch-on-to-fault
schemes) — at the beginning of the first calendar quarter 39 months following
applicable regulatory approvals.

Approved by Board of Trustees: TBD

Standard PRC-023-12 — Transmission Relay Loadability
5.1.3 Each Transmission Owner, Generator Owner, and Distribution Provider shall have
24 months after being notified by its Planning Coordinator pursuant to
Requirement R5, Part R53.3 to comply with Requirement R1 (including all subrequirements) for each facility that is added to the Planning Coordinator’s critical
facilities list determined pursuant to Requirement
R5, Part R35.1.
5.2. Requirement R53: 18 months following applicable
regulatory approvals.
B. Requirements
R1.

FERC Order 733, ¶244:
Include section 2 of Appendix
A as an additional
Requirement.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1, Settings1.1 through R1.13) for any specific circuit
terminal to prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the Bulk Electric SystemBES for all fault
conditions, and to prevent its out-of-step blocking schemes from blocking tripping for fault
conditions. Each Transmission Owner, Generator Owner, and Distribution Provider shall
evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees:
[Violation Risk Factor: High] [Mitigation Time Horizon: Long Term Planning]. Settings:
1.11.

Set transmission line relays so they do not operate at or below 150% of the highest
seasonal Facility Rating of a circuit, for the available defined loading duration nearest
4 hours (expressed in amperes).

1.22.

Set transmission line relays so they do not operate at or below 115% of the highest
seasonal 15-minute Facility Rating2 of a circuit (expressed in amperes).

1.33.

Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sendingend and receiving-end voltages and either reactance or complex impedance) of the
circuit (expressed in amperes) using one of the following to perform the power
transfer calculation:
1.3.1• An infinite source (zero source impedance) with a 1.00 per unit bus voltage
at each end of the line.
1.3.2• An impedance at each end of the line, which reflects the actual system
source impedance with a 1.05 per unit voltage behind each source impedance.

1.4.

Set transmission line relays on series compensated transmission lines so they do not
operate at or below the maximum power transfer capability of the line, determined as
the greater of:
•

115% of the highest emergency rating of the series capacitor.

-• 115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with R1.3Requirement R1, Setting 3, using the
full line inductive reactance.
1.45.

Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in
amperes).

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Approved by Board of Trustees: TBD

Standard PRC-023-12 — Transmission Relay Loadability
1.56.

Set transmission line relays applied on transmission lines connected to generation
stations remote to load so they do not operate at or below 230% of the aggregated
generation nameplate capability.

1.67.

Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current
flow from the load to the generation source under any system configuration.

1.78.

Set transmission line relays applied on the bulk system-end of transmission lines that
serve load remote to the system so they do not operate at or below 115% of the
maximum current flow from the system to the load under any system configuration.

1.89.

Set transmission line relays applied on the load-end of transmission lines that serve
load remote to the bulk system so they do not operate at or below 115% of the
maximum current flow from the to the under any system configuration.

1.910.

Set transformer fault protection relays and
transmission line relays on transmission lines
terminated only with a transformer so that they do
not operate at or below the greater ofsuch that the
protection settings do not expose the limiting piece
of equipment to fault level and duration that exceeds
its capability and so that the relays do not operate at
or below the greater of::

FERC Order 733, ¶203:
Modify sub-requirement R1.10
to verify equipment is capable
of sustaining the anticipated
overload associated with the
fault.

-• 150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.
-• 115% of the highest operator established emergency transformer rating.
1.1011. For transformer overload protection relays that do not comply with Requirement R1,
Setting 1.10 set the relays according to one of the following:
-• Set the relays to allow the transformer to be operated at an overload level of at least
150% of the maximum applicable nameplate rating, or 115% of the highest operator
established emergency transformer rating, whichever is greater, . The protection
must allow this overload for at least 15 minutes to allow provide time for the operator
to take controlled action to relieve the overload.
-• Install supervision for the relays using either a top oil or simulated winding hot spot
temperature element. The setting should be set no less than 100° C for the top oil
temperature or no less than 140° C for the winding hot spot temperature 3.
1.1112. When the desired transmission line capability is limited by the requirement to
adequately protect the transmission line, set the transmission line distance relays to a
maximum of 125% of the apparent impedance (at the impedance angle of the
transmission line) subject to the following constraints:
1.12.1a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by
the manufacturer.

Approved by Board of Trustees: TBD

Standard PRC-023-12 — Transmission Relay Loadability
1.12.2b.Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
1.12.3c. Include a relay setting component of 87% of the current calculated in
Requirement R1, Setting 121.12.2 in the Facility Rating determination for the circuit.
1.1213. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

The Each Transmission Owner, Generator Owner, or and Distribution Provider that uses a
circuit capability with the practical limitations described in Requirement R1, Settings1.6, R1.7,
R1.8, R1.9, R1.12, or R1.13 shall use the calculated circuit capability as the Facility Rating of
the circuit and shall obtain the agreement of the Planning Coordinator, Transmission Operator,
and Reliability Coordinator with the calculated circuit capability. [Violation Risk Factor:
Medium] [Time Horizon: Long Term Planning]

R3.

FERC Order 733, ¶186: Modify
TheEach Transmission Owner, Generator Owner, orand
R1.2 to require that TOs, GOs,
Distribution Provider that sets transmission line relays
and DPs give their TOPs a list of
according to Requirement R1 part 1.2Setting 2 shall provide
transmission facilities that
their its Planning Coordinator, Transmission Operator,
implement R1.2.
Regional Entity, and Reliability Coordinator with a list of
transmission ffacilities that haveassociated with those transmission line relays set so they do
not operate at or below 115% of the highest seasonal 15-minute Facility Rating at least once
each calendar year, with no more than 15 months between reports as described in R1.2.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
FERC Order 733, ¶203: Modify
Planning]
sub-requirement R1.10 to verify

The Transmission Owner, Generator Owner, or Distribution
equipment is capable of
Provider that sets transformer fault protection relays and
anticipated overload.
transmission line relays on transmission lines terminated only
with a transformer based on the limitations described in R1.10 shall verify that the protection
setting does not expose the limiting piece of equipment to fault level and duration that exceeds
its capability. [Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
R4.

Each Transmission Owner, Generator Owner, orand
Distribution Provider that sets transmission line relays
according to Requirement R1 part 1.Setting 12 shall provide a
list of the facilities associated with those relays to theirits
Regional Entity at least once each calendar year, with no more
than 15 months between reports. [Violation Risk Factor:
Lower] [Time Horizon: Long Term Planning]

R3.R5.
The Each Planning Coordinator shall apply the criteria
in Attachment B to determine which of the facilities (transmission lines operated at below100
kV to 200 kV and transformers with low voltage terminals
Attachment B is still
connected at 100 kV tobelow 200 kV) in its Planning Coordinator
under development.
Area are critical to the reliability of the Bulk Electric SystemBES
to identify the facilities from 100 kV tobelow 200 kV that must
meet Requirement R1 to prevent potential cascade trippingcascading that may occur when
protective relay settings limit transmission loadability. [Violation Risk Factor: High] [Time
Horizon: Long Term Planning]
5.1

The Planning Coordinator shall have a process to use the criteria established within
Attachment B to determine the facilities that are critical to the reliability of the Bulk
Electric System.

Approved by Board of Trustees: TBD

Standard PRC-023-12 — Transmission Relay Loadability
1.3.1

This process shall consider input from adjoining Planning Coordinators and
affected Reliability Coordinators.

5.2

The Each Planning Coordinator shall maintain a current
list of facilities determined according to the process
described in Requirement R5 pPart 53.1.

5.3

The Each Planning Coordinator shall provide a list of
facilities to its Regional Entity, Reliability
Coordinators, Transmission Owners, Generator Owners,
and Distribution Providers within 30 calendar days of the establishment of the initial
list and within 30 calendar days of any changes to the that list.

Approved by Board of Trustees: TBD

FERC Order 733, ¶237:
Modify sub-requirement
R3.3 to add the RE to
list of entities that
receive the critical
facilities list.

Standard PRC-023-12 — Transmission Relay Loadability
PRC-023 — Attachment A
1.

FERC Order 733, ¶264: Revise
section 1 of Attachment A to
include supervising relay
elements.

1.6. Relay elementsProtective functions that supervise operation of other protectiveon functions
in 1.1 through 1.5.
2.

This standard includes out-of-step blocking schemes which shall be evaluated to ensure
that they do not block trip for faults during the loading conditions defined within the
requirements.

3.2.

The following protection systems are excluded from requirements of this standard:

3.1.2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications.

3.2.2.2. Protection systems intended for the detection of ground fault conditions.
3.3.2.3. Protection systems intended for protection during stable power swings.
3.4.2.4. Generator protection relays that are susceptible to load.
3.5.2.5. Relay elements used only for Special Protection Systems applied and approved in
accordance with NERC Reliability Standards PRC-012 through PRC-017 or their
successors.
3.6.2.6. Protection systems that are designed only to respond in time periods which allow 15
minutes or greater to respond to overload conditions.
3.7.2.7. Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.
3.8.2.8. Relay elements associated with DC dc lines.
3.9.2.9. Relay elements associated with DC dc converter transformers.

Approved by Board of Trustees: TBD

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project
2010-13)
Please DO NOT use this form. Please use the electronic form located at the link below to
submit comments on the proposed standard, PRC-023-2 and on the associated SAR. The
electronic comment form must be completed by September 19, 2010.
https://www.nerc.net/nercsurvey/Survey.aspx?s=c64a2b0a1f9d4e98aef8640932516830
If you have questions please contact Stephanie Monzon at Stephanie.monzon@nerc.net or
by telephone at [610-608-8084
Project 2010-13: Relay Loadability Order (RLO SDT) – PRC-023-2
Background Information
NERC Standard PRC-023-1 – Transmission Relay Loadability was approved by FERC as
mandatory and enforceable in March 2010, with direction that NERC make a number of
changes.
The Standard Drafting Team has made changes to PRC-023 to address the following
directives from Order 733
• p. 60 . . . modify PRC-023-1 to apply an “add in” approach to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that become
Registered Entities in the future, and are associated with a facility that is included on a
critical facilities list defined by the Regional Entity.
• p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.
• p. 203 . . . modify sub-requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated overload for the
longest clearing time associated with the fault.• p. 224 . . . make available for review to
users, owners and operators of the Bulk-Power System, by request, a list of those
facilities that have protective relays
• p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]
• p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.
• p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on
the list of relays and protection systems that are specifically subject to the Reliability
Standard.
• p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.
• p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)

However, the directive below is not yet addressed, even though it is referenced within the
draft standard text. It will be included in a subsequent posting of this draft standard.
• p. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.
To expedite the project to address the directives from FERC Order No. 733, the Standard
Drafting Team is posting the draft modifications to PRC-023-1 for an informal comment
period.
Please note that the posting of PRC-023-2 is an INFORMAL posting.

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)

1. The Applicability Section (4.1.2 and 4.1.4) and Requirement R5 (previously
Requirement R3) have been modified to address the directive in Paragraph 60 of
Order no. 733. Do you agree that this is an acceptable and effective method of
meeting this directive? If not, please explain.
Yes
No
Comments:
2. Requirement R1 has been modified to address the directive in Paragraph 244 of
Order no. 733. Do you agree that this is an acceptable and effective method of
meeting this directive? If not, please explain.
Yes
No
Comments:
3. Requirement R1, section 10 has been modified to address the directive in Paragraph
203 of Order no. 733. Do you agree that this is an acceptable and effective method
of meeting this directive? If not, please explain.
Yes
No
Comments:
4. Requirement R3 has been added to address the directive in Paragraph 186 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting
this directive? If not, please explain.
Yes
No
Comments:
5. Requirement R4 has been added to address the directive in Paragraph 224 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting
this directive? If not, please explain.
Yes
No
Comments:
6. Requirement R5 and part 5.1 (previously Requirement R3 and part 3.1) have been
modified to establish the framework to address the directive in Paragraph 69 of
Order no. 733, although the criteria itself (which will be Attachment B) is still being

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)

developed. Do you agree that this is an acceptable and effective method of meeting
this directive considering that Requirement R5 is establishing the construct to insert
the criteria at a future time in the form of Attachment B? If not, please explain.
Yes
No
Comments:
7. Attachment A has been modified to address the directive in Paragraph 264 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting
this directive? If not, please explain.
Yes
No
Comments:
8. Do you agree that the SDT has addressed the remaining directives: Paragraph 284 to
remove the footnote and Paragraph 283 to modify the implementation plan for sub100 kV facilities (by revising the Effective Date section of the standard)?
Yes
No
Comments:
Questions 9-13 relate to the SAR
9. Do you agree that the scope of the proposed standards action addresses the
directive or directives?
Yes
No
Comments:
10. Can you identify an equally efficient and effective method of achieving the reliability
intent of the directive or directives?
Yes
No
Comments:

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project 2010-13)

11. Do you agree with the scope of the proposed standards action?
Yes
No
Comments:

12. Are you aware of any regional variances that we should consider with this SAR?
Yes
No
Comments:

13. Are you aware of any associated business practices that we should consider with this
SAR?

Yes
No
Comments:

Standard Authorization Request Form
Title of Proposed Standard

Relay Loadability Order 733

Request Date

8/5/2010

SC Approval Date

8/12/2010

SAR Requester Information
Name

SAR Type (Check a box for each one
that applies.)

Stephanie Monzon

New Standard

Primary Contact
Stephanie.monzon@nerc.net

Revision to existing Standard

Telephone

610-608-8084

Withdrawal of existing Standard

Stephanie.monzon@nerc.net

Urgent Action

Fax
E-mail

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Standards Authorization Request Form

Purpose As the ERO, NERC must address all directives in Orders issued by FERC. On March
18, 2010 FERC issued Order No. 733 which approved Reliability Standard PRC-023-1 –
Transmission Relay Loadability, and also directed NERC, as the Electric Reliability
Organization (“ERO”), to develop certain modifications to the PRC-023-1 standard through
its Reliability Standards development process, to be completed by specific deadlines.
Attachment 1 to the SAR contains the directives and associated deadlines. The Order also
directed development of two new Reliability Standards to address issues related to
generator relay loadability and the operation of protective relays due to power swings. The
standards-related directives in Order 733 are aimed at closing some reliability-related gaps
in the scope of PRC-023-1.

Industry Need
FERC directed NERC to develop modifications related to Relay Loadability by specific
deadlines in Order No. 733. Attachment 1 to the SAR contains the directives and associated
deadlines.
PRC-023-1 Directed Modifications
The Commission directed a number of changes to the approved standard including a test to
be applied by Planning Coordinators to determine applicability to elements operated at less
than 200 kV. This test will be included in PRC-023-1 either in the form of a Requirement or
as an attachment to the standard.
Generator Step-up and Auxiliary Transformers
The Commission directed the ERO to develop a new Reliability Standard addressing
generator relay loadability, with its own individual timeline, and not a revision to an existing
Standard.
Protective Relays Operating Unnecessarily Due to Stable Power Swings
The Commission observed that PRC-023-1 does not address stable power swings, and
pointed out that currently available protection applications and relays, such as pilot wire
differential, phase comparison and blinder-blocking applications and relays, and impedance
relays with non-circular operating characteristics, are demonstrably less susceptible to
operating unnecessarily because of stable power swings. Given the availability of
alternatives, the Commission stated that the use of protective relay systems that cannot
differentiate between faults and stable power swings constitutes miscoordination of the
protection system and is inconsistent with entities’ obligations under existing Reliability
Standards.
In this Final Rule the Commission decided not to direct the ERO to modify PRC-023-1 to
address stable power swings. However, because both NERC and the U.S.-Canada Power
System Outage Task Force have identified undesirable relay operation due to stable power
swings as a reliability issue, the Commission directed the ERO to develop a Reliability
Standard that requires use of protective relay systems that can differentiate between faults
and stable power swings and, when necessary, phases out protective relays that cannot
meet this requirement.

Brief Description
This SAR’s scope includes three standard development phases to address the standardsrelated directives in Order No. 733 directives. Phase I is focused on making the specific
modifications to PRC-023-1 that were identified in the order; Phase II is focused on
SAR–2

Standards Authorization Request Form

developing a new standard to address generator relay loadability; and Phase III is focused
on developing requirements that address protective relay operations due to power swings.
Detailed Description
Phase I: Develop modifications to PRC-023-1- Transmission Relay Loadability by March 18,
2011 to address the following directives from Order 733:
•

p. 60 . . . modify PRC-023-1 to apply an “add in” approach to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that become
Registered Entities in the future, and are associated with a facility that is included on a
critical facilities list defined by the Regional Entity.

•

p. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.

•

p 162 . . . consider “islanding” strategies that achieve the fundamental performance for
all islands in developing the new Reliability Standard addressing stable power swings.

•

p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.

•

p. 203 . . . modify sub-requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated overload for the
longest clearing time associated with the fault.

•

p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]

•

p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.

•

p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the Reliability
Standard.

•

p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.

•

p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.

In Phase I of the project, the NERC Relay Loadability standard drafting team will either
modify the PRC-023-1 Reliability Standard to incorporate the directed modifications or will
propose equally efficient and effective alternative approaches that address the Commission’s
reliability-related concerns. (In parallel with this effort, NERC plans to convene a panel of
industry subject matter experts to develop a straw man proposal for the test Planning
Coordinators must use to identify sub-200 kV facilities that are critical to the reliability of
the Bulk Power System. The panel will collect industry feedback on the straw man test
using the current standards development process that will be incorporated into Requirement
R3 of PRC-023-1 by the Standard Drafting Team.)
Phase II: Develop a new Standard Addressing Generator Relay Loadability
In Phase II of the project, a new Reliability Standard will be developed by the end of 2012
to address the subject of generator relay loadability in support of NERC’s filing indicating it
would develop such a standard and to address the following directive from Order No. 733:
•

p. 108 . . . consider the PSEG Companies’ suggestion in developing a Reliability
SAR–3

Standards Authorization Request Form

Standard that addresses generator relay loadability.
As indicated in NERC’s Order No. 733 clarification and rehearing request, NERC believes
adding additional requirements to the PRC-023 standard in addition to developing a new
Reliability Standard to address generator relay loadability could lead to confusion over
applicability and the possibility of conflicting requirements. Therefore, NERC proposed in its
clarification and rehearing request to address the issue of generator relay loadability in a
new Reliability Standard, separate and distinct from the PRC-023 Reliability Standard, which
is intended to address relays that protect transmission elements. Subject to the
Commission’s response to NERC’s pending clarification and rehearing request, NERC plans
to address generator relay loadability in a new Reliability Standard for applications where
the relays are set with a shorter reach to protect the generator and the generator step-up
transformer, and for applications where the relays are set with a longer reach to provide
backup protection for transmission system faults. The standard drafting team will use
relevant sections of the NERC technical reference document, Power Plant and Transmission
System Protection Coordination Section 3.1 and Appendix E to develop the requirements by
which generator relay loadability will be assessed.
Phase III: Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings
In Phase III of the project, a new Reliability Standard will be developed to address the
subject of protective relay operations due to power swings to address the following directive
from Order No. 733 by the end of 2014:
•

p. 150 - develop a Reliability Standard that requires the use of protective relay systems
that can differentiate between faults and stable power swings and, when necessary,
phases out protective relay systems that cannot meet this requirement.

SAR–4

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–5

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–6

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

PRC-023-1

Order No. 733 approved Reliability Standard PRC-023-1 – Transmission
Relay Loadability, and directed NERC, as the Electric Reliability
Organization (“ERO”), to develop certain modifications to the PRC-023-1
standard through its Reliability Standards development process, to be
completed by specific deadlines.

New Reliability
Standard

Development of a New Standard Addressing Generator Relay Loadability

New Reliability
Standard

Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC

SAR–7

Attachment 1 - Order No. 733 – Action Plan and Timetable
Note that the scope of the SAR is
Order No. 733 approved Reliability Standard PRC-023-1 – Transmission
limited to addressing the directives
Relay Loadability, and directed NERC, as the Electric Reliability
highlighted in the table below.
Organization (“ERO”), to develop certain modifications to the PRC-023-1
standard through its Reliability Standards development process, to be
completed by specific deadlines and directed NERC to develop requirements to address issues related to Relay
Loadability. The Order also directed development of two new Reliability Standards to address issues related to
generator relay loadability and the operation of protective relays due to power swings. The following table lists the
FERC directives in Order No. 733 and for each directive associates it with a project phase. Note that some of the
tasks within each phase will be managed by NERC staff, not the standard drafting team.

Paragraph

Text

Project Phase/
Timeline

With respect to sub-100 kV facilities, we adopt the NOPR proposal and direct
the ERO to modify PRC-023-1 to apply an “add in” approach to sub-100 kV
facilities that are owned or operated by currently-Registered Entities or entities
that become Registered Entities in the future, and are associated with a facility
that is included on a critical facilities list defined by the Regional Entity. We
also direct that additions to the Regional Entities’ critical facility list be tested
for their applicability to PRC-023-1 and made subject to the Reliability
Standard as appropriate.

Phase I -- by
March 18, 2011

Finally, pursuant to section 215(d)(5) of the FPA, we direct the ERO to modify
Requirement R3 of the Reliability Standard to specify the test that planning
coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System. We direct the ERO to file its test, and
the results of applying the test to a representative sample of utilities from each
of the three Interconnections, for Commission approval no later than one year
from the date of this Final Rule.

Phase I -- Note
NERC’s pending
request for
rehearing filed on
April 19, 2010
regarding this
directive.

Finally, commenters argue that there should be some mechanism for entities to
challenge criticality determinations. We agree that such a mechanism is
appropriate and direct the ERO to develop an appeals process (or point to a
process in its existing procedures) and submit it to the Commission no later
than one year after the date of this Final Rule.

Phase I – by
March 18, 2011

105

In light of the ERO’s statement that within two years it expects to submit to the
Commission a proposed Reliability Standard addressing generator relay
loadability, we direct the ERO to submit to the Commission an updated and
specific timeline explaining when it expects to develop and submit this
proposed Standard.

Phase II – by the
end of 2012

108

Finally, the PSEG Companies suggest that the ERO consider whether a generic
rating percentage can be established for generator step-up transformers and, if
so, determine that percentage. Although we do not adopt the NOPR proposal,
we encourage the ERO to consider the PSEG Companies’ suggestion in
developing a Reliability Standard that addresses generator relay loadability.

Phase II – by the
end of 2012

150

However, because both NERC and the Task Force have identified undesirable
relay operation due to stable power swings as a reliability issue, we direct the
ERO to develop a Reliability Standard that requires the use of protective relay
systems that can differentiate between faults and stable power swings and,

Phase III – by the
end of 2014

Attachment 1 - Order No. 733 – Action Plan and Timetable

Paragraph

Text

Project Phase/
Timeline

when necessary, phases out protective relay systems that cannot meet this
requirement. We also direct the ERO to file a report no later than 120 days of
this Final Rule addressing the issue of protective relay operation due to power
swings. The report should include an action plan and timeline that explains
how and when the ERO intends to address this issue through its Reliability
Standards development process.
162

We agree with the PSEG Companies and direct the ERO to consider
“islanding” strategies that achieve the fundamental performance for all islands
in developing the new Reliability Standard addressing stable power swings.

Phase I – by
March 18, 2011

186

However, we will adopt the NOPR proposal to direct the ERO to modify PRC023-1 to require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that
implement sub-requirement R1.2.

Phase I – by
March 18, 2011

203

We adopt the NOPR proposal and direct the ERO to modify sub-requirement
R1.10 so that it requires entities to verify that the limiting piece of equipment
is capable of sustaining the anticipated overload for the longest clearing time
associated with the fault.

Phase I – by
March 18, 2011

224

While we are not adopting the NOPR proposal, we direct the ERO to
document, subject to audit by the Commission, and to make available for
review to users, owners and operators of the Bulk-Power System, by request, a
list of those facilities that have protective relays set pursuant sub-requirement
R1.12.

Phase I – by
March 18, 2011

237

We adopt the NOPR proposal and direct the ERO to modify the Reliability
Standard to add the Regional Entity to the list of entities that receive the
critical facilities list. [sub-requirement R3.3]

Phase I – by
March 18, 2011

244

We adopt the NOPR proposal and direct the ERO to include section 2 of
Attachment A in the modified Reliability Standard as an additional
Requirement with the appropriate violation risk factor and violation severity
level.

Phase I – by
March 18, 2011

264

After further consideration, and in light of the comments, we will not direct the
ERO to remove any exclusion from section 3, except for the exclusion of
supervising relay elements in section 3.1. Consequently, we direct the ERO to
revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the
Reliability Standard.

Phase I – by
March 18, 2011

283

Additionally, in light of our directive to the ERO to expand the Reliability
Standard’s scope to include sub-100 kV facilities that Regional Entities have
already identified as necessary to the reliability of the Bulk-Power System
through inclusion in the Compliance Registry, we direct the ERO to modify the
Reliability Standard to include an implementation plan for sub-100 kV
facilities.

Phase I – by
March 18, 2011

Attachment 1 - Order No. 733 – Action Plan and Timetable

Paragraph

Text

Project Phase/
Timeline

284

We also direct the ERO to remove the exceptions footnote from the “Effective
Dates” section.

Phase I – by
March 18, 2011

297

Finally, we direct the ERO to assign a “high” violation risk factor to
Requirement R3.

Filed with the
Commission on
April 19, 2010

308

Consequently, we direct the ERO to assign a single violation severity level of
“severe” for violations of Requirement R1.

Filed with the
Commission on
April 19, 2010

310

Accordingly, we direct the ERO to change the violation severity level assigned
to Requirement R2 from “lower” to “severe” to be consistent with Guideline
2a.

Filed with the
Commission on
April 19, 2010

311

Finally, we direct the ERO to assign a “severe” violation severity level to
Requirement R3.

Filed with the
Commission on
April 19, 2010

Standards Announcement

Standards Authorization Request (SAR) and Draft Standard
Formal and Informal Comment Periods Open
August 19–September 19, 2010
Now available at:
http://www.nerc.com/filez/standards/Reliability_Standards_Under_Development.html
Project 2010-13: Revisions to Relay Loadability for Order 733
The drafting team associated with this project is seeking comments on a proposed SAR and an
initial set of proposed requirements until 8 p.m. Eastern on September 19, 2010.
The SAR is being posted for a 30-day formal comment period and the standard is being posted
for a 30-day informal comment period; comments on both the SAR and the proposed
requirements will be collected using a single comment form.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using
the electronic form, please contact Monica Benson at monica.benson@nerc.net. An off-line,
unofficial copy of the comment form is posted on the project page:
http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
Next Steps
The drafting team will draft and post responses to comments received during this period.
•

The SAR is being posted for a 30-day formal comment period. With a formal comment
period the team is required to provide a response to each comment submitted.

•

The proposed requirements in the standard are being posted for a 30-day informal
comment period. With an informal comment period, for each question asked on the
comment form, the drafting team will provide a summary response to indicate whether
stakeholders support the proposed revision and to identify any additional changes made
based on stakeholder comments. The team will not provide an individual response to
each comment submitted.

Project Background
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it
directed several changes to that standard and also directed development of one or more new
standards within specified time periods. NERC filed for clarification and rehearing asking for
clarity and an extension of time to address the directives, however without a response to the

requests for clarification and rehearing, NERC must progress as though these requests will be
denied.
The SAR for Project 2010-13 subdivides the standard development related directives into three
phases. Phase I addresses the specific directives from Order 733 that identified required
modifications to various elements within PRC-023-1. Phase II addresses directives associated
with development of a new standard to address generator relay loadabilty. Phase III addresses
directives associated with writing requirements to address protective relay operations due to
power swings.
Applicability of Proposed PRC-023-2
Distribution Providers that own specific facilities (see standard for details)
Generator Owners that own specific facilities (see standard for details)
Planning Coordinators
Transmission Owners that own specific facilities (see standard for details)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.

Individual or group. (36 Responses)
Name (20 Responses)
Organization (20 Responses)
Group Name (15 Responses)
Lead Contact (15 Responses)
Question 1 (32 Responses)
Question 1 Comments (36 Responses)
Question 2 (29 Responses)
Question 2 Comments (36 Responses)
Question 3 (29 Responses)
Question 3 Comments (36 Responses)
Question 4 (29 Responses)
Question 4 Comments (36 Responses)
Question 5 (27 Responses)
Question 5 Comments (36 Responses)
Question 6 (32 Responses)
Question 6 Comments (36 Responses)
Question 7 (32 Responses)
Question 7 Comments (36 Responses)
Question 8 (26 Responses)
Question 8 Comments (36 Responses)
Question 9 (27 Responses)
Question 9 Comments (36 Responses)
Question 10 (25 Responses)
Question 10 Comments (36 Responses)
Question 11 (27 Responses)
Question 11 Comments (36 Responses)
Question 12 (29 Responses)
Question 12 Comments (36 Responses)
Question 13 (29 Responses)
Question 13 Comments (36 Responses)
Individual
Gene Henneberg
NV Energy
Yes
No
The proposed phrase added to R1 is only a start: “. . . , and to prevent its out-of-step blocking schemes from blocking
tripping for fault conditions.” The specific wording proposed by the Drafting Team may prevent using the out-of-step-block
functions of many modern and widely used line protection relays (e.g. SEL-321 and later models and GE-UR). These
relay’s OSB function first blocks the protection elements from tripping, then uses a short delay and/or other information to
determine whether the observed and perhaps evolving condition really represents a fault, in which case the blocking is
reset to allow tripping. Such a block/reset operation is the most common technology available and would appear to lie
within the intent of FERC in paragraph 244, but could be excluded by the presently proposed language. If an out-of-step
blocking phrase is inserted in Requirement R1 of the standard, the emphasis should be modified to read something like: “.
. . , and its out-of-step blocking schemes must allow tripping for fault conditions.” This standard should also require that
out-of-step blocking settings coordinate with both the loadability and protection characteristics. The out-of-step blocking
references would seem to fit best within the organization of the standard if included as a new Requirement R2 (FERC’s
paragraph 244 anticipates “. . . an additional Requirement . . .”), with re-numbering of the proposed R2 through R5 as R3
through R6. The essential content of the DT’s proposed phrase in R1 would be included as part of this new R2, which
would read something like: R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall evaluate its
out-of-step blocking schemes to ensure that both: R2.1. Out-of-step blocking schemes allow tripping for fault conditions
during the loading conditions determined from Requirement R1 parts R1.1 through R1.13. R2.2. Relay out-of-step
blocking settings coordinate with both the relay loadability characteristic determined from Requirement R1 parts R1.1
through R1.13 and the facility protection settings. The Measure for this proposed R2 would read something like: M2.The
Transmission Owner, Generator Owner, and Distribution Provider with out-of-step blocking schemes shall have evidence
such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking schemes is set to comply
with the requirements of R2.1 and R2.2. The VSL for R1 would not change; specifically it would not reference out-of-step
blocking schemes. The VSL for this proposed new R2 would be “Severe” and read something like: A Transmission Owner,
Generator Owner, or Distribution Provider did not allow its out-of-step blocking schemes to trip for fault conditions during
the loading conditions determined from Requirement R1 parts R1.1 through R1.13. OR A Transmission Owner, Generator
Owner, or Distribution Provider did not coordinate operation of its out-of-step blocking schemes with both the relay

loadability characteristic determined from Requirement R1 parts R1.1 through R1.13 and the facility protection settings.
Yes
Yes
Yes
No
This approach is not yet an acceptable and effective method of meeting the directive of paragraph 69. Whether it becomes
an acceptable and effective method of meeting the directive will depend on the content of Attachment B. I’ll reserve
specific judgment and concerns until Attachment B is available for comment.
Yes
Yes
Yes
No
NERC's proposed Phase I, II, II process seems reasonable.
Yes
No

Individual
Steve Wadas
NPPD
Yes
As long as you keep BES.
Yes
I'm ok with that. It could have easily been left in Attachment A. You didn't bring the other language from attachment A to
R1. You could of created a separate requirement for OOS, but I'm fine with moving it to R1.
No
Setting the relay to 150% of a 336MVA or 500MVA transformer can force you to cross the transformer damage curve and
now your transformer is at risk to loss of life.
Yes
Yes
No
Attachment B has not even been developed.
No
Please remove Attachment A, R1.6. "Protective functions that supervise operation of other protection functions in 1.1
through 1.5.". If you do not remove R1.6 you must provide a detailed explanation of what supervise operation means and
give examples. Utilities have thousands of relays that have imbedded fault detective supervision overcurrents for phase
distance elements that are set at 0.5 amps or some similar value. This can not be changed. From your requirement these
utilities would have to replace all of these relays or we would have to lower the Facality rating to 0.5 amp
secondary/150%. You are also stating that if we have an external phase overcurrent fault detector that supervises a phase
distance relay that this fault detector must now have to meet Requirement 1. This is an unacceptable requirement if this is
your intent. You are putting the system at risk if this is your intent. We must set our relays to protect the line. We must also
set fault detectors to pickup for all faults considering N-1 conditions at a minimum where the strongest source must be
remove and the relays must still clear the fault. Please do not lose focus of the purpose: "Protective relay settings shall be
set to reliably detect all fault conditions and protect the electrical network from these faults". If you have questions on my
comments feel free to contact me. Steve Wadas, NPPD, 402 563 5917 Wk.
Yes
No
No
No

No
Yes
See Question 7.
Group
E.ON U.S. LLC
Brent Ingebrigtson
No
E.ON U.S. believes that it is confusing the way R5 is currently written due to the last part of the sentence “ … when
protective relay settings limit transmission loadability.” There is a need for clarification on how this is to be applied. As an
alternative: If the directive is to have the Planning Coordinator determine which sub-100kV facilities should be subject to
the Reliability Standard; R5 should be modified to read “Each Planning Coordinator shall apply the criteria in Attachment B
to determine which of the facilities in its Planning Coordinator Area are to be included in 4.1.2 and 4.1.4.”
No
Since correct operation of the out-of-step blocking feature is integral to and only a single component of a successful trip
operation (for fault conditions), this is already included in the requirement to “maintain reliable protection of the BES for all
fault conditions” and does not have to be mentioned separately. Also, R1 (as written) may be interpreted to require one of
the settings (1 through 13) to be used to prevent out-of-step blocking schemes from blocking tripping for fault conditions.
But Settings 1 thru 13 do not address specific setting criteria for out-of-step blocking.
No
E.ON U.S. is concerned that the proposal requires a fault protection scheme separate from the phase overload relays.
With the phase overload relays set at 150% of the maximum transformer nameplate, they (by themselves) will not be able
to coordinate with the transformer damage curve (as defined by IEEE) for low level faults. R1, Section 10 meets the
directive of Paragraph 203; however it is not clear that Section 10 only applies when there is no high side breaker at the
transformer, as discussed in Order No. 733. E.ON U.S. recommends that an exclusion of the transmission line relay
settings should be considered when transformer overload protection is provided by other means (i.e. A low side breaker
trip or a direct transfer trip of the remote breaker initiated by an overload relay installed on the transformer).
Yes
Yes
No
See comments for item #1.
No
E.ON U.S. requests a clarification of “protective functions” such that it applies only to those protective relay elements that
would respond to non-fault or load conditions, and could issue a direct trip, upon operation, during a loss of
communication or loss of potential condition.
No
Cannot assess the impact until Attachment B is developed and commented sections above are clarified.
No
See commented sections above. Also, the directive identified in Paragraph 224 was not included in the detailed
description or highlighted in Attachment 1 of the SAR. However it was included in the proposed modifications as R4.
Yes
No
No
No
Individual
Joylyn Faust
Consumers Energy
Yes
Yes
Yes
Yes
Yes

Yes
We are concerned about the criteria still undergoing development, and will offer any relevant comments on that criteria
when it is published.
No
The supervising elements addressed within this change may fundamentally be unable to be set in accordance with the
requirements of PRC-023, while still permitting the Protection System to function properly for fault conditions. The
supervising element is usually present to assure that a distance element does not operate inadvertently for close-in zerovoltage faults near the relay location in the non-trip direction, but does not, by itself, produce a trip. We appreciate that
NERC must respond to this directive, but believe that the change, as expressed, will be detrimental to reliability.
Yes
Yes
Yes
NERC should, again, oppose the FERC directive in paragraph 264, since, as explained above, this directive is both
unnecessary and detrimental to reliability.
Yes
No
No
Individual
Jonathan Meyer
Idaho Power - System Protection
Yes
Yes
No
The reworded Requirement should to be clarified. The fault level and duration that the limiting element will be exposed can
be a function of fault location and contingencies, such as relay failures, that are not addressed or defined. No measure is
specified in the reliability standard that will demonstrate compliance with the revised requirements in R1.10.
Yes
Yes
No
It is not acceptable or effective until Attachment B is completed and available for review.
Yes
The order has been met, but there is significant concern about the inclusion of supervisory elements in protective systems.
A supervisory element is not performing a tripping function. As stated in Attachment A “This standard includes any
protective functions which could trip with or without time delay, on load current, including but not limited to:…”. Supervisory
elements, used properly, do not trip for load current.
Yes
Yes
No
Yes
No
No
Group
Northeast Power Coordinating Council
Guy Zito
No

The revised Applicability paragraph 4.1.4 reads: 4.1.4 Transformers with low voltage terminals connected below 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System (BES). The phrase "low
voltage terminals" is open to interpretation because some transformers have low-voltage terminals which are do not
supply a load, or supply only local substation AC service. Sometimes the transformer is a 3-winding bank, with the lowvoltage winding not used, or the low-voltage winding is used solely to provide additional grounding, as in the case of a
delta-connected tertiary, unconnected to any load. Is this what is intended? If yes, then they should remove the ambiguity.
Note the phrase "low-voltage" terminal was part of Revision 1 and is unchanged by Revision 2, however, the new
applicability to below 200 kV raises the new concern. What is meant by “critical to the reliability of the Bulk Electric System
(BES)”? Also, replace “as designated” with “and designated”. Suggest 4.1.4 be revised to read: 4.1.4 Transformers with
low voltage terminals connected below 200 kV and designated by the Planning Coordinator as Critical Assets. Clarification
is needed to explain the disconnect between FERC’s “sub-100kV”, and the proposed “below 200kV”.
No
The last sentence in R1 should be revised to read: Each Transmission Owner, Generator Owner, and Distribution provider
shall evaluate relay loadability at 0.85 per unit voltage, and a power factor angle of 30 degrees. Settings are to be applied
as listed following: “Setting” should be replaced throughout R1 when referring to a part, or sub-requirement of R1. The
terminology should be whatever is preferred by NERC. Requirement R1, Parts 7, 8 and 9: Requirement R1, Parts 7, 8 and
9, replace the phrase “under any system configuration” with "under any system condition:" 7. Set transmission line relays
applied at the load center terminal, remote from generation stations, so they do not operate at or below 115% of the
maximum current flow from the load to the generation source under any system condition. 8. Set transmission line relays
applied on the bulk system-end of transmission lines that serve load remote to the system so they do not operate at or
below 115% of the maximum current flow from the system to the load under any system condition. 9. Set transmission line
relays applied on the load-end of transmission lines that serve load remote to the bulk system so they do not operate at or
below 115% of the maximum current flow from the [___] to the under any system condition. [Brackets added, also see
further comment on missing wording following] This phrase "under any system configuration" could be construed as being
too all-inclusive, as one could postulate multiple events, e.g., simultaneous outages, which however unlikely could permit
power flows in a direction for which the system was not originally designed. As with the second comment below, the
phrase "under any system condition" was part of Revision 1 and is unchanged by Revision 2, however, the new
applicability to below 200 kV creates the new concern. Requirement 1, part 9: As currently written, Requirement 1, part 9
states: 9. Set transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk
system so they do not operate at or below 115% of the maximum current flow from the [___] to the under any system
configuration. [Brackets added] Some words are missing. The brackets have been added above to show one place where
at least some of the needed wording may be missing. A rewrite is necessary in order for this sentence to make any sense.
Yes
No
Referring to the response to Question 2 above, “Setting” should be replaced with Part, or Sub-requirement, whichever is
the terminology preferred by NERC to use.
No
R4 addresses the directive, but as commented on previously, “Setting” should be replaced with Part, or Sub-requirement,
whichever is the terminology preferred by NERC to use.
No
Requirement R5 states that the Planning Coordinator will determine which facilities below 200kV are critical to the
reliability of the Bulk Electric System by applying criteria defined in Attachment B, which is to be developed. Therefore,
respondents cannot comment on Attachment B. Respondents reserve the right to comment when Attachment B is
available for review. Because the document has been presented to the industry without Attachment B, how will
Attachment B be presented to the industry? Regarding sub-requirement 5.3, it must be revised to clarify that the Planning
Coordinator will provide the list of facilities subject to the Standard to all of the TOs, GOs, and DPs registered in its
footprint, not just to those entities that have facilities on the list. 5.2 refers to “Part 1”. As commented on previously in
Question 5 and elsewhere, Part or Sub-requirement should be used for consistency.
Yes
Yes
Yes
No
Yes
No
No
Individual
Michael Gammon
Kansas City Power & Light

No
Agree the changes for 4.1.2 and 4.1.4 are effective in meeting the “add in” approach in the FERC order. However, do not
agree with the approach in R5. R5 proposes to establish the criteria by which Reliability Coordinators will determine
facilities critical to the reliability of the BES. There are a variety of differing, and often complex, operating conditions that
dictate the need for transmission facilities. The TPL standards require extensive studies of the transmission system be
performed under steady state and dynamic conditions to understand and identify sensitive areas of the transmission
system and enable Reliability Coordinators to identify flowgates in their respective regions. In light of the Reliability
Coordinators awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to the
Reliability Coordinators additional criteria.
Yes
No
Although setting #10 includes language to protect the most limiting element for a transmission circuit ending with a
transformer, the relay settings in the bulleted items are absent any consideration for other elements such as disconnect
switches, wave traps, current transformers, potential transformers, etc. and are only with concern to the transformer. The
relay settings should consider the fault current capabilities of all the facilities involved and be set in magnitude and
duration of the lowest facility rating.
No
Do not agree that the Regional Entity be included as a recipient of the list of transmission facilities. By NERC definition,
the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is not an
operating entity. It is inappropriate to include Regional Entities as an entity to provide this information outside of the audit
process established by the NERC Rules of Procedure. By definition, in the NERC Reliability Terminology, the Regional
Entity is a compliance enforcement agent and not an operating organization of the Bulk Power System, and, therefore,
has no operating reason to obtain this information. See definition below: Regional Entity – The term ‘regional entity’ is
defined in Section 215 of the Federal Power Act means an entity having enforcement authority pursuant to subsection
(e)(4) [of Section 215]. A regional entity (RE) is an entity to which NERC has delegated enforcement authority through an
agreement approved by FERC. There are eight RE’s. The regional entities were formed by the eight North American
regional reliability organizations to receive delegated authority and to carry out compliance monitoring and enforcement
activities. The regional entities monitor compliance with the standards and impose enforcement actions when violations
are identified.
No
The proposed R4 exceeds the concerns of FERC in this matter. FERC directed a requirement to provide information upon
request. The proposed R4 requires data submission without request of the parties with interest to the information.
Recommend the SDT consider modifying this requirement to provide this information upon the request of appropriate
operating parties. Do not agree that the Regional Entity be included as a recipient of the list of transmission facilities. By
NERC definition, the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability
Standards and is not an operating entity. It is inappropriate to include Regional Entities as an entity to provide this
information outside of the audit process established by the NERC Rules of Procedure. By definition, in the NERC
Reliability Terminology, the Regional Entity is a compliance enforcement agent and not an operating organization of the
Bulk Power System, and, therefore, has no operating reason to obtain this information. See definition below: Regional
Entity – The term ‘regional entity’ is defined in Section 215 of the Federal Power Act means an entity having enforcement
authority pursuant to subsection (e)(4) [of Section 215]. A regional entity (RE) is an entity to which NERC has delegated
enforcement authority through an agreement approved by FERC. There are eight RE’s. The regional entities were formed
by the eight North American regional reliability organizations to receive delegated authority and to carry out compliance
monitoring and enforcement activities. The regional entities monitor compliance with the standards and impose
enforcement actions when violations are identified.
No
Do not agree with the approach in R5 and R5.1. This proposes to establish the criteria by which Reliability Coordinators
will determine facilities critical to the reliability of the BES. There are a variety of differing, and often complex, operating
conditions that dictate the need for transmission facilities. The TPL standards require extensive studies of the transmission
system be performed under steady state and dynamic conditions to understand and identify sensitive areas of the
transmission system and enable Reliability Coordinators to identify flowgates in their respective regions. In light of the
Reliability Coordinators awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to
the Reliability Coordinators additional criteria. In addition, in R5.3, do not agree that the Regional Entity be included as a
recipient of the list of transmission facilities. By NERC definition, the Regional Entity is the Compliance Monitor and
Enforcement Authority for the NERC Reliability Standards and is not an operating entity. It is inappropriate to include
Regional Entities as an entity to provide this information outside of the audit process established by the NERC Rules of
Procedure. By definition, in the NERC Reliability Terminology, the Regional Entity is a compliance enforcement agent and
not an operating organization of the Bulk Power System, and, therefore, has no operating reason to obtain this
information. See definition below: Regional Entity – The term ‘regional entity’ is defined in Section 215 of the Federal
Power Act means an entity having enforcement authority pursuant to subsection (e)(4) [of Section 215]. A regional entity
(RE) is an entity to which NERC has delegated enforcement authority through an agreement approved by FERC. There
are eight RE’s. The regional entities were formed by the eight North American regional reliability organizations to receive
delegated authority and to carry out compliance monitoring and enforcement activities. The regional entities monitor
compliance with the standards and impose enforcement actions when violations are identified.
Yes
No
It is inappropriate for this standard to supersede any other agreements and the provisions of those agreements that have
been established between NERC and Registered Entities. The footnote made it clear those agreements would continue to

be honored. Recommend the SDT reinstate the principles established by the footnote directly into the Effective Dates
section to recognize the authority of those agreements. Agree with the effective dates of 18 months after applicable
approvals for R5 and for 24 months after notification by the Planning Coordinator of a new critical facility.
Yes
Agree that the SDT has made revisions that attempted to address the FERC directives. Do not agree with all the
proposals by the SDT as indicated by the comments regarding questions 1 through 8.
No
No other comments.
No
Do not agree with all the proposals by the SDT as indicated by the comments regarding questions 1 through 8.
No
No
Group
Transmission Access Policy Study Group
William Gallagher
No
The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make all DPs
potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the standard is applicable to
them. Because PRC-023 should never be applicable to a DP in its capacity as a DP (as opposed to a TO that also
happens to be registered as a DP), as explained in TAPS’ response to question 6 below, the SDT should simply remove
DPs from the Applicability section to prevent the significant potential for confusion and unnecessary costs.

No
The proposed method of identifying facilities to which the standard will apply may be reasonable, though we cannot
comment definitively until a draft of Attachment B is available. The standard should not be applicable to DPs, however.
TAPS has been unable to find or think of an example in which a DP would have a load-responsive transmission phase
protection system, aside from a DP that is also a TO and has such a phase protection system because of its TO function.
There is thus no reason to include DPs as potentially applicable entities. If the SDT retains DPs on the list of potentially
applicable entities, it should at minimum clarify Requirement R5.3 to state that the Planning Coordinator will provide the
list of facilities subject to the standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who
have facilities on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.

Individual
Dan Rochester
Independent Electricity System Operator
Yes
We agree with the Applicability Section and the modification to R5. Note that there is a discrepancy between the entities
listed in the Applicability Section and those checked off in the SAR. The latter indicates that the SAR is also applicable to
the RC, which we do not believe is required.
No
We agree with the inclusion of Section 2 of Attachment A in the Requirement Section but the proposed modification may
not fully meet the directive that the additional requirement is assigned a VRF and VSL. This may require the creation of a
separate main requirement rather than simply including the condition as a part of a requirement.
No
The proposed revision goes beyond what’s asked for in the directive as it requires the responsible entities to provide the
list to entities other than the TOP. The directive asks for providing the list to the TOP only.
No
The objective of R4 as written is unclear. We speculate that by requiring the TOs, GOs and DPs to provide the list
(associated with R1, Section 12) to the REs, the ERO will collect the relevant information from all REs to facilitate

provision of such information to owners, users and operators of the BES upon request. If this is the intent, we suggest to
replace “REs” with “ERO” to make it a more direct and efficient way to provide the information needed to support the
request for information process. The requirement as written does not conform with the results-based concept in that it
does not clearly specify a reliability directive. Hence alternatively, we suggest removal of this requirement altogether since
the directive asks the ERO to document, subject to audit by the Commission, and to make available for review to users,
owners and operators of the Bulk-Power System, by request, a list of those facilities. This can be dealt with outside of the
standard process, for example, through RoP 1600.
No
We are unable to assess its acceptability and effectiveness until Attachment B is developed.
Yes
No
We are unable to comment on this in the absence of a proposed implementation plan.
Yes
As indicated in our comment submitted under Q1, there is a discrepancy between the entities listed in the Applicability
Section and those checked off in the SAR. The latter indicates that the SAR is also applicable to the RC, which we do not
believe is required.
Yes
We general agree with the proposed action but there are detailed changes that we have comments on, which are noted in
our comments under Q1 to Q8
No
No
Individual
Bill Miller
ComEd
Yes
Yes
Yes
Yes
Yes
Yes
No
1) Certain relay elements may be thought to be “supervising relay elements”, when their function is specific and more
limited. A very common example would be a phase overcurrent relay that is required to actuate along with a phase
distance relay to cause a trip. In many applications, the phase overcurrent relays function is only to assure that the phase
distance relay will not cause a trip when a line is taken out of service and no potential restraint is applied to the phase
distance relay. Thus, loadability of the phase overcurrent relay is not a concern. Raising the level of the overcurrent
element may negatively impact the fault detecting ability of the two relays. This is perhaps a limited function supervising
relay element. It is complementary to the phase distance relay which provides the necessary loadability. 2) Although we
don’t employ out of step tripping, it would seem that the argument for the overcurrent element of an out of step tripping
scheme would be the same as for the phase distance element. 3) Are there supervisory elements for switch onto fault
schemes that could limit loadability? 4) In our experience, relays that supervise overcurrent relays are typically specifically
designed to provide loadability in order to allow the overcurrent relay to provide greater sensitivity without worrying about
its loadability. Thus this requirement would limit the use of such a scheme. 5) FERC’s main example seems to refer to an
old style of current differential relaying scheme that is likely not very widely applied. Most modern current differential
schemes use digital communications and will not trip on loss of communications regardless of the settings of any elements
that may be considered to be supervisory relay elements. The drafting team should consider modifying 1.6 of Attachment
A to clarify and more specifically address the FERC concern. Three suggestions are as follows: 1) 1.6. Protective
functions that supervise operation of other protective functions in 1.5. This is required for communications aided protection
schemes in 1.5 only when those schemes require communication channel integrity to maintain scheme loadability. 2) 1.6.
Protective functions that supervise operation of other protective functions in 1.2 through 1.5. This is required for
communications aided protection schemes in 1.5 only when those schemes require communication channel integrity to
maintain scheme loadability. 3) 1.6. Protective functions that supervise operation of other protective functions in 1.2
through 1.5.
Yes

Yes
No
No, other than the comments provided for question 7.
Yes
Yes, given that we assume that NERC must address all the FERC directives whether or not NERC or the industry agrees
with them.
No
No
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
Yes
No
Item 1.6 in Attachment A is not necessary. If the protection functions in 1.1 through 1.5 already meet all the loadability
requirements, the facility would not trip under heavy load condition by the supervising protection element alone. The
directive in paragraph 264 of Order 733 seems to deal with the supervising protection element on the current differential
scheme only. It is still arguable whether it is better to allow tripping of the line or restrain from tripping during loss
communication and heavy loading condition.
No
Even though this version of the standard does seem to have addressed Paragraph 284 of Order 733, we still do not agree
with the uniform effective date without taking into consideration how many critical circuits or equipment could be added for
an individual utility.
Yes
Yes
The effective date can be dependent upon how many critical circuits or equipment are identified for each individual
company.
Yes
No
No
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
No
Agree with the content. However, there is no justification for VRF to be High for the circuits lower than 200 kV.
Yes
Yes
Yes
No
FERC Order required the list to be made available for review to users, owners and operators of the Bulk-Power System

upon request. Requirement 4 does not include the "request" requirement, implying that the Registered Entity must provide
the list without a request. Further, the requirement does not specify what the Regional Entity will do with the list once it is
provided.
Yes
Yes

Yes

Yes
No
No
Individual
Brian Evans-Mongeon
Utility Services
No
The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make all DPs
potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the standard is applicable to
them. Because PRC-023 should never be applicable to a DP in its capacity as a DP (as opposed to a TO that also
happens to be registered as a DP), as explained in our response to question 6 below, the SDT should simply remove DPs
from the Applicability section to prevent the significant potential for confusion and unnecessary costs.

No
The proposed method of identifying facilities to which the standard will apply may be reasonable, though we cannot
comment definitively until a draft of Attachment B is available. The standard should not be applicable to DPs, however. We
have been unable to find or think of an example in which a DP would have a load-responsive transmission phase
protection system , aside from a DP that is also a TO and has such a phase protection system because of its TO function.
There is thus no reason to include DPs as potentially applicable entities. If the SDT retains DPs on the list of potentially
applicable entities, it should at minimum clarify Requirement R5.3 to state that the Planning Coordinator will provide the
list of facilities subject to the standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who
have facilities on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.

Group
Pepco Holdings, Inc - Affiliates
Richard Kafka
Yes
While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities that are not
defined as BES facilities) we believe that as long as a sound engineering methodology is developed and applied uniformly
to identify those facilities critical to the reliability of the BES, then the revised wording is acceptable. Our response,
however, is qualified based on being granted an opportunity to comment and vote on the methodology once it is
developed.
No
The revised wording in paragraph R1 regarding out-of-step blocking schemes is confusing. We suggest rewording the
paragraph by splitting the sentence as follows: …while maintaining reliable protection of the BES for all fault conditions.
Use of out-of-step blocking schemes shall be evaluated to ensure that they do not block tripping for faults during the
loading conditions defined within these requirements.
No

It would appear that this requirement has already been addressed in the R1 introductory paragraph by the phrase “...while
maintaining reliable protection of the BES for all fault conditions.” How could one “maintain reliable protection of the BES”
if relays are set with operating times that result in equipment being exposed to fault levels and durations that exceed their
capability. This introductory requirement to provide reliable fault protection applies to all sub requirements not just to
section 10 (old R1.10). As such, the added language in section 10 seems redundant and superfluous. Secondly, if the
proposed language were to remain in section 10, why is the term “limiting piece of equipment” used and not just
“transformer”? It appears the major concerns related to the comments contained in Order 733 were around exceeding
transformer fault level/duration limitations. If that is the concern, why not just use the phrase “do not expose the
transformer to fault levels and durations that exceeds its capability”
No
To avoid confusion, the wording of R3 should be revised as follows: “Each Transmission Owner, Generator Owner, and
Distribution Provider that chooses to utilize Requirement R1 Setting 2 as the basis for verifying transmission line relay
loadability shall provide….” The problem with the SDT’s proposed wording of R3 is that suppose a TO chose to utilize R1
Setting 1 criteria (> 150% of 4 hr rating) as their basis for verifying loadability, but the actual relay setting also satisfied
criteria R1 Setting 2 (> 115% of 15 min rating) the entity may interpret that they are still obligated to forward the list since
the relay settings also satisfied R1 Setting 2 criteria
Yes
Yes
While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities that are not
defined as BES facilities) we believe that as long as a sound engineering methodology is developed and applied uniformly
to identify those facilities critical to the reliability of the BES, then the revised wording is acceptable. Our response,
however, is qualified based on being granted an opportunity to comment and vote on the methodology contained in
Attachment B once it is developed.
No
We do not agree with the proposed wording of Section 1.6 of Attachment A which makes the standard apply to “Protective
functions that supervise operation of other protective functions in 1.1 through 1.5”. The standard should apply to
“protective systems” not individual components of protective systems. Compliance should be based on the ability of the
“protective system” as a whole to meet the performance criteria established by the standard. Delving into the details of
individual scheme designs and supervising element operation goes well beyond the purpose and scope of this standard.
In paragraph 251 of Order 733 the Commission “expressed concern that section 3.1 could be interpreted to exclude
certain protection systems that use communications to compare current quantities and directions at both ends of a
transmission line, such as pilot wire protection or current differential protection systems supervised by fault detector
relays” and requested comment on “whether it should direct the ERO to modify section 3.1 to clarify that it does not
exclude from the requirements of PRC-023-1 pilot wire protection or current differential protection systems supervised by
fault detector relays.” The Commission reiterated again in paragraphs 266, 268, and 270 their concern with not including
supervising elements associated with “current differential schemes” to prevent them for operating on loss of
communications. That being said, the proposed revision to Attachment A to include supervising elements for all protective
functions in 1.1 through 1.5 goes well beyond addressing the Commission’s concern. We believe the Commission’s
concern could be addressed by simply modifying Attachment A by deleting proposed section 1.6 and adding a new
section 1.5.5 “Line current differential schemes, including supervising overcurrent elements”. The SDT’s current proposed
wording for Section 1.6 would require the overcurrent element in a switch-on-to-fault scheme to be subject to the
loadability criteria. However, the NERC SPCTF in their June 7, 2006 technical paper “Switch-on-to-Fault Schemes in the
Context of Line Relay Loadability” indicated there is no suggested loadability criterion if the voltage arming threshold is set
low enough. Similarly, fault detectors which supervise distance elements would be subject to the loadability standard.
However, there are no criteria established on how to set these elements, particularly on weak source systems, or zone 3
applications, where in order to reliably detect faults at the end of the zone of protection may require setting the supervising
fault detector below 150% of line rating. The NERC SPCTF in their June 7, 2006 technical paper “Methods to Increase
Line Relay Loadability” provided recommendations to increase loadability of distance elements through various
techniques, such as the use of load encroachment elements or blinders, but does not specifically address setting of
supervising elements. In fact, at present, there is no reliability standard requiring the use of supervising elements, and
some newer microprocessor relays do not even employ supervising fault detectors on their distance elements. FERC in
their Order 733 stated “As with our other directives in this Final Rule, we do not prescribe this specific change as an
exclusive solution to our reliability concerns regarding the exclusion of supervising relay elements. As we have stated, the
ERO can propose an alternative solution that it believes is an equally effective and efficient approach to addressing the
Commission’s reliability concerns.” In summary, we believe that addressing the Commission’s concern regarding
supervising elements on current differential schemes, as described in our second paragraph above, would satisfy the
intent of Order 733, while not imposing unnecessary additional restrictions on what has proven historically to be extremely
reliable protection practices.
No
We agree with the removal of the footnote regarding temporary exceptions. However, there appears to be a contradiction
between the effective dates for sub 200kV facilities noted in section 5.1.2 (39 months following regulatory approvals) and
5.1.3 (24 months after being notified by its Planning coordinator). If the planning coordinator takes the full 18 months to
determine the R5 list (per effective date section 5.2) and the TO has 24 months after that to comply, that would be 42
months following regulatory approval, which is in conflict with the 39 month requirement in 5.1.2. Since the list of sub
200kV facilities may change from year to year, it would seem prudent to make the effective date for those facilities always
tied to a defined interval following being notified by the Planning Coordinator and eliminate the 39 month requirement for
sub 200kV facilities from 5.1.2. Also, since the Attachment B methodology has not yet been determined, it is unclear how
many sub 200kV facilities may fall under these requirements. As such, one cannot yet determine if the proposed 24
months would be sufficient. We propose at least a 36 month interval until the methodology is finalized and the magnitude
of the scope better defined. In addition, if supervising elements are included in the standard in some form, an

implementation schedule (i.e. appropriate effective dates) need to be developed based on this significant increase in
scope and number of facilities to be reviewed.
Yes
While the scope of the proposed standards action addresses the directive(s) outlined in FERC Order 733 we believe that
there are two significant issues that need to be much more thoroughly investigated before being included. Those areas
are the inclusion of supervising elements in the existing relay loadability standard and the development of any new
standard that would “require the use of protective relay systems that can differentiate between faults and stable power
swings and when necessary phase out protective relay systems that cannot meet this requirement.”
Yes
Regarding the response of protective relay systems to stable power swings, Draft 5 of TPL-001-2 Requirement R4
(stability assessment) section 4.3.1 requires a contingency analysis be performed which includes “tripping of transmission
lines and transformers where transient swings cause protection system operation based on generic or actual relay
models.” Therefore the impact of power swings on relay operation is already addressed in TPL-001. If the tripping of a line
is identified during this study phase the impact of the line trip is assessed to ensure the system meets the performance
criteria identified in Table 1. If not, mitigating measures would be required, such as modifying that protection scheme to
prevent its operation during a stable power swing. However, this would be done on a case by case basis when identified.
This seems a much more prudent approach than to require “all protection systems be modified to prevent operation during
stable power swings.” That would be similar to requiring the re-conductoring all lines so that they could never experience
an overload. Also, Appendix F of the “PJM Relay Subcommittee Protective Relaying Philosophy and Design Standards”
employs a methodology to address relay response during power swings by calculating a transient load limit for the relay
instead of just the steady state limit identified in PRC-023. The relay loadability is evaluated at the maximum projection
along the +R axis (the most susceptible point for swings to enter) rather than at a 30 degree load angle. Various
multiplying factors are used to account for the relay operating time delay. This methodology of calculating relay transient
loadability limits, which was developed by the PJM Relay Subcommittee over 30 years ago, has worked extremely well in
eliminating relay operations during stable power swings. In summary, there are other methods to evaluate and improve the
performance of protection systems during power swings short of hardware replacements. All options should be evaluated.
No
We do not agree with the scope of the proposed standards action for numerous reasons. The documented responses to
the original FERC NOPR on PRC-023 from numerous sources, including NERC and EEI, together make a rather
convincing technical argument against many of these proposed actions. We support these technical arguments, which for
the sake of brevity will not be repeated here. In addition, we have provided comments and objections on specific portions
of the proposed standards action in our responses to questions 1 through 10 above.
No
No
Group
American Transmission Company
Andrew Z. Pusztai
Yes
However, this affirmative response is conditional depending on whether the criteria that will be established within
Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV.
Yes
Yes
The word change meets the strict interpretation of the directive, but it is not necessarily improving the reliability of the
system. Faults are cleared in cycles and transformer damage curves do not start until at least one second.
Yes
Yes
While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.
No
As noted in Q1 above, an affirmative response would be conditional and depend on whether the criteria that will be
established within Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV. In
addition, the R5 requirement should include wording that limits the scope of the transmission facilities (line and
transformer circuits) to be evaluated to only those transmission facilities that can be tripped by the relay settings subject to
requirement R1. Requirement R5 should also qualify that only the transmission facilities that are “known” to be associated
with the relay settings subject to requirement R1 need to be evaluated. If the SDT wants to better assure that the Planning
Coordinator knows about all of the pertinent transmission facilities, then they should add a requirement that obligates
Transmission Owners, Generator Owners, and Distribution Providers to provide the Planning Coordinator with a list of the
transmission facilities that are associated with the relay setting subject to requirement R1.
No
In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two components
of reliability for protective relays. The Commission did not recognize that the two tend to be mutually exclusive. Raising
dependability (making sure breakers trip during a fault) can sacrifice some degree of security (tripping more than is
needed). Historically, protection engineers have been biased toward dependability to ensure the safety of people and

equipment. The exclusions allow that to happen. These are contingency scenarios where protective schemes are
compromised. For a second contingency, the dependability is at risk if fast tripping is not employed. By removing the
exclusion, reliability could be negatively jeopardized. For example, an operational decision to open breakers will be
needed for loss of potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until
the loss of potential condition can be diagnosed and corrected
Yes
Yes
It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.
Yes
On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the inclusion of
qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities that are not tripped by the
applicable relay settings).
No
We agree that the topics of generator relay loadability and power swing protective relaying should be referred to in other
separate standards. While we acknowledge that it is in everyone’s best interest to respond to the FERC directives, there
are numerous technical flaws that need to be resolved in their request. Forming a team and spending considerable
resources will not gain industry acceptance to these directives.
No
No
Individual
Tribhuwan Choubey
Southern California Edison
No
Applicability clause 4.12 and 4.14 - Formulating a consistent methodology test to determine for a sub 200KV facility by the
Planning Coordinator is quite an uphill task keeping in view the different circuit configuration different utilities may have. It
is best left alone to each utility to determine the facilities which can be a candidate for inclusion as a bulk power system.
The current risk based assessment criteria to determine bulk power facility should be continued.
No
Requirement R1.7, R1.8, R1.13 do not provide a clear guideline on generators connected to the load center on Radial
basis, where load current into the generators ( forward direction current seen by the relay) is just an auxiliary load and
insignificant compared to the transmission line rating.
No
The relay if set according to Requirement R1.2 are based upon 15 minute highest seasonal facility loading duration. This
gives sufficient time for the operators to take manual corrective action, if the deem so. There is no need for the Registered
entity to provide a list, as it would not be efficient and cost effective.

Group
PSEG Companies
Kenneth D. Brown

No
In attachment A was added a new requirement, item 1.6. We not agree with this. Sometimes these elements have to be
set lower than the criteria. As long as the protection system as a whole does not trip the line, then that should meet the
criteria. Individual elements that supervise tripping element should NOT be part of the standard.

No
No
Individual
Dale Fredrickson
Wisconsin Electric
No comment
No comment
No comment
No comment
No comment
No comment
No
We strongly disagree with this change. Applying the loadability requirement to supervisory functions in protection system
will have an extremely negative effect on BES reliability. With this change, protection systems will be less dependable,
resulting in increased probability of a failure to detect a system fault. This change should not be implemented.
No comment
No comment
No comment
No comment
No
No
Group
PacifiCorp
Sandra Shaffer
Yes

Yes
Yes
Yes
Yes
No
Paragraph No. 264 directs a revision to Section 1 of Attachment A in order to include supervising relay elements. This
change as currently written requires further clarification to meet this directive. For example, a Distance element is
commonly supervised by a phase overcurrent element (Fault detector). If this change suggests that the overcurrent
element has to be set above maximum load, then PacifiCorp disagrees with the modification. The fault detector will not trip
the line by itself; it operates to qualify the distance element assertion. It is our standard practice to set this element above
load where possible, but without restricting the reach of the distance element. This means that if the fault current at the
maximum reach of the distance element is below load, setting the fault detector above load will restrict the reach of the
distance element- this would compromise the protection scheme. In microprocessor relays where Load encroachment is
used this is even more critical. The Load encroachment function will prevent the distance element from operating in the
load region and a fault detector setting that is sensitive enough can be used safely without the need to set it above load
current to enhance the distance element reach.
Yes
No
No
It is very difficult to comment on test parameters that have not been determined.

No
No
Group
Southern Company
Andy Tillery
Yes
Yes
Yes
Yes
Yes
Yes
No
The language that has been added to PRC-023 related to the inclusion of protection elements (fault detectors) supervising
protection functions that are subject to the PRC-023-2 requirements is not appropriate and will likely decrease the
reliability of the BES for the following reasons: - The tripping logic utilizing these elements is an AND function, it takes
distance element AND the fault detector (FD) to trip. Since all distance elements meet the loadability criteria, it is not
necessary to also ensure FD meet hese requirements. - Setting FD above nominal load point would unnecessarily reduce
sensitivity of distance element and in many cases eliminate the distance element’s ability to protect the very system
element it is designed and intended to protect - It would require very expensive communications based relay schemes to
replicate this lost protection if it is even possible to do so; a long radial line is one instance where it would not be possible Eliminating the FD would actually reduce Security and Dependability in electromechanical schemes - There is a whole
generation of microprocessor based relays that it is not possible to eliminate the FD; to effectively take it out of service,
one would have to set it to the most sensitive setting which would violate the loadability criteria - Relays at terminals with
high SIR, a weak source system, and line with large conductors where the far end fault current may be smaller than
maximum line current (similar to Exception 6 of the Relay Loadability Exceptions: Determination and Applications of
Practical Relaying Loadability Ratings, Version 1.1 published November 2004 by the System Protection and Control Task
Force of NERC) - Faults with low power factor could present a similar magnitude of line current as normal high power
factor load currents
Yes
Yes
No
Yes
No
No
Group
Bonneville Power Administration
Denise Koehn
Yes
No
The modified Requirement R1 requires that one of the 13 criteria be used to prevent out-of-step blocking schemes from
blocking tripping for fault conditions. The problem is that the 13 criteria are only related to loading conditions, and it is not
clear how they would be applied to prevent out-of-step blocking schemes from blocking a trip during a fault, or if it is even
possible to use these criteria for this purpose. The modified Requirement R1 requires actions that are ambiguous and we
cannot support it as written.
No
In some cases, Section 10 of Requirement R1 would be impossible to meet. For example, a 150/200/250 MVA,
OA/FOA1/FOA2 transformer is required by Section 10 to have its protection set so that it doesn’t operate at or below
150% of the maximum transformer rating of 250MVA, or 1.5x250=375MVA. The modified Section 10 would also require

that the protection not expose the transformer to a fault level and duration that exceeds its capability. According to IEEE
C37.91, a through-fault of two times the transformers base rating, 2x150=300MVA, will be damaging to the transformer.
For this particular transformer, which is not unusual, Requirement R1, Section 10, requires the protection to operate for
through faults of 300MVA or greater, but not operate for loads of 375MVA or less. It is impossible to simultaneously meet
both of these conditions, so Section 10 is unacceptable. One possible way to correct the problem is to change the
requirement so that the protection does not operate below 200% of the transformer base rating. This would allow the
protection to meet IEEE C37.91 for through-faults and still allow overloading of the transformer.
This change adds an additional burden to the applicable entities, but serves no purpose other than to satisfy FERC’s
misinterpretation of what a fifteen-minute facility rating is.
No
Requirement R5 is okay, but Part 5.1 adds an additional and useless extra burden to the applicable entities. The process
that the Planning Coordinator is required by this part to have would almost certainly be to simply apply the criteria in
Attachment B to lines and transformers operated below 200kV to determine if they are critical to the BES. Requiring
documentation for such a trivial process results in increased paper work, additional preparation for an audit, and is a
waste of everyone’s time. We suggest deleting Part 5.1.
No
Here we have a situation where the standard is being compromised to satisfy FERC’s misunderstanding of what a
supervising relay is. In Paragraph 266, FERC gives an example of how a line differential relay works in an attempt to
demonstrate why supervisory elements must not operate for load, but instead they clearly demonstrate their
misunderstanding of the details of differential relay operation and what a supervisory relay is. Modern differential relays
will disable the differential function upon loss of communications. If an overcurrent element is present, it would be used for
backup protection, not as a supervisory element. If an overcurrent element were used to supervise a differential element,
the sensitivity of the differential relay would be lost and the result would be a simple overcurrent relay. FERC’s
misunderstanding has resulted in the improper addition of supervisory relays in Attachment A, Section 1. Sometimes
supervisory relays must be set below maximum loading to obtain the purpose they were intended for. For example, it is
often necessary to set overcurrent supervision of distance relays below the maximum load current of the line so that they
will operate for remote faults. This modification to Attachment A would prohibit that action and make it impossible to set
the supervisory relays to comply with the standard and still provide adequate protection. The modification to Attachment A
is unacceptable.
5.1.2 and 5.1.3 both apply to the same systems and should be combined into one sub-requirement. Also, since the date of
the applicable regulatory approval is now established, please consider replacing the cryptic phrase “at the beginning of the
first calendar quarter 39 months following applicable regulatory approval” with an actual date.
Yes
No
Yes
No
No
Individual
Kathleen Goodman
ISO New England Inc.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
Some immediate concerns with the proposal include: 1) Our understanding is that the application of NERC standards is
limited to the BES. Thus, facilities below 100 kV must be included in the Regional Entity definition of BES to be eligible.
The requirements should reflect this. The way the proposed standard reads, one might conclude the PC must test every
facility below 100 kV. This surely can’t be the intent. 2) Furthermore, the directive appears to require some action on the
Regional Entities. From paragraph 60, “We also direct that additions to the Regional Entities’ critical facility list be tested
for their applicability to PRC-023-1 and made subject to the Reliability Standard as appropriate.” It is not clear how this
directive is reflected in the standard to ensure that this work is completed prior to the PC’s performing their assessment for
below 200 kV facilities. The bottom line is that the changes here are significant enough that they would benefit from a
group of experts reviewing the directives and proposing the precise language that is needed.
No
Requirement R1, Parts 7, 8 and 9: Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration”
with "under any system condition:" 7. Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current flow from the load to the generation
source under any systemcondition. 8. Set transmission line relays applied on the bulk system-end of transmission lines
that serve load remote to the system so they do not operate at or below 115% of the maximum current flow from the
system to the load under any systemcondition. 9. Set transmission line relays applied on the load-end of transmission
lines that serve load remote to the bulk system so they do not operate at or below 115% of the maximum current flow from
the [___] to the under any system condition. [Brackets added, also see further comment on missing wording following]

This phrase "under any system configuration" could be construed as being too all-inclusive, as one could postulate
multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in a direction for which the
system was not originally designed. As with the second comment below, the phrase "under any system condition" was
part of Revision 1 and is unchanged by Revision 2, however, the new applicability to below 200 kV creates the new
concern. Requirement 1, part 9: As currently written, Requirement 1, part 9 states: 9. Set transmission line relays applied
on the load-end of transmission lines that serve load remote to the bulk system so they do not operate at or below 115%
of the maximum current flow from the [___] to the under any system configuration. [Brackets added] Some words are
missing. The brackets have been added above to show one place where at least some of the needed wording may be
missing. A rewrite is necessary in order for this sentence to make any sense.
Yes
No
We do not understand the need for this directive or requirement. A relay that is set to operate at 115% greater than the 15minute rating of the facility does not equate to damage occurring on that facility if operated at that point in 15 minutes.
Furthermore, it does not mean the relay will operate in 15 minutes nor does it mean the operator has only 15 minutes to
take action. In fact, the operator may have less time depending on the time delay set on the relay. It is no different than
any other relay. Usually, the facility will be operated with some buffer so that there is no chance that an entity could trip the
facility due to loading above the relay limit. In fact, the transmission operator should be aware of any relay that might be
the limiting facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.
Yes
Yes
Yes
No
While we agree removing the footnote is straight forward and addresses one Commission directive. In particular, we
believe that only a full drafting team could adequately assess if any additional time will be needed to comply with the
standard for sub-100 kV facilities particularly when we consider there are some outstanding issues a regional entities
critical facilities list identified in Question 1. Also, we are unable to assess if the two directives are fully addressed absent a
proposed implementation plan.
Yes
No
We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is the purpose
for convening a full drafting team and that the drafting team should propose their alternatives.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that the scope be
modified to make clear that the drafting may use equally effective alternatives to address the Commission’s directives per
the Commission in this order and other orders such as Order 693. The scope should address apparent conflicts in the
timing of requirements posed by the standard. It is our understanding that, based on the final date afforded NERC to
develop the criteria for the determination of sub-200 kV facilities,a newly proposed implementation plan will be offered to
allow the Planning Coordinators an appropriate time frame to apply the criteria to determine the “critical” facilities below
200 kV. The implementation plan should cause the effective date for circuits described in 4.1.2 and 4.1.4 to be changed
from “39 months following applicable regulatory approvals” to a date linked to the Planning Coordinators schedule to
provide a list to its TOs, GOs and DPs.
No
We are not aware of any regional variances per se. However, each regional entity has its own definition for BES and this
needs to be considered when addressing sub-100 kV facilities.
No
Individual
Robert Ganley
Long Island Power Authority
No
There appears to be a disconnect between FERC’s “sub 100 kV” and proposed “below 200 kV” revision in the Applicability
Section. LIPA seeks clarification on this. Also, by whom and by which method will the criticality of the substations be
ascertained?
No
Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration” with "under any system condition:"
This phrase "under any system configuration" could be construed as being too all-inclusive, as one could postulate
multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in a direction for which the
system was not originally designed. Requirement 1, part 9: As currently written, Requirement 1, part 9 states: 9. Set
transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk system so they do
not operate at or below 115% of the maximum current flow from the [___] to the under any system configuration. [Brackets

added] Some words are missing. The brackets have been added above to show one place where at least some of the
needed wording may be missing. A rewrite is necessary in order for this sentence to make any sense.
Yes
Yes
No
FERC order 733 p224 requires that the list of facilities that have protective relays set pursuant to R1.12 of anticipated
overload be made available to users, owners, and operators of the BPS. However, the proposed revision to R4 requires
the list to be made available to Regional Entity only. Please clarify. Also, FERC order uses the term “by request” which is
missing from the proposed revision.
No
LIPA understands the drafting team’s rationale, however, believes that the proposed method in Attachment B should be
developed before providing comments.
No
LIPA believes that the new wording in 1.6 Attachment A is unnecessary since the existing wording already complies with
the FERC order p.264. Supervisory functions are already part of the protective functions 1.1 through 1.5. Also, this new
wording will be subject to varied interpretation and create more confusion.
No
Yes
Yes
Involving industry working groups such as IEEE, EPRI, etc who have proven technical experts will also help in effectively
achieving reliability.
Yes
LIPA agrees with the scope in general. Please consider our comments above for answers to specific issues.
Yes
NPCC BPS definition based on A10 criteria is a regional variance.
No
Individual
Kirit Shah
Ameren
No
Attachment B as mentioned in R5 is not available for review.
Yes
No
The language is not clear. It appears that the transmission line relays are being used as the thermal overload protection
for the transformer.
Yes

No
See our response to Question 1
No
In attachment A – 1.6 is not a tripping function – it’s a supervisory function – it in itself does not trip which is the description
of ‘1’ therefore needs to be elsewhere if kept.
Yes

No
No
Individual
Thad Ness
American Electric Power

No
AEP understands the intent of the FERC Order (Paragraph 60) to address the sub-100 KV facilities only if they are
associated with critical facilities above 100 KV. The applicability and the associated requirements should be reworded to
ensure that the Planning Coordinator does not have to identify critical facilities below 100 KV.
Yes
Yes
Yes
Yes
No
Please refer to our comment under question number 1. AEP reserves the right to provide additional comments once
Attachment B has been drafted and supplied for industry review.
No
AEP requests some clarifying information regarding what is envisioned for 1.6 of Attachment A.
No
It is unclear how much time a TO, GO, or DP would have to implement the changes based on the results of the analysis
by the Planning Coordinator. In addition, the Effective Date section is a one-time event upon regulatory approval. What
are the on-going implementation expectations? There should be some allowed lead beyond initial implementation after
facilities are identified by the Planning Coordinator.
No
Refer to our comment under question 1.
No
Not at this time, but AEP would like to consider all viable options throughout the standard development process.
Yes
No
No
Individual
Michael Moltane
ITC Holdings
Yes
No
The proposed wording seems out of place in this requirement and is not clear as how it is being applied to
subrequirements 1 - 13
No
R1 -10 is all about loadability of the relays protecting the transformer. If the requirements of R1-10 cannot be met without
exceeding the transformer damage curve, then we go to R1-11. We do not feel that there should be anything to do with
fault duty.
Yes
Yes
Yes
No
It appears from the new 1.6 (Attachmnt A) that fault detectors must meet loadability requirements. These do not trip and
must not be included in PRC023. We will not be able to adequately protect longer lines in weak areas with this
requirement in place.
No
The new effective dates for 5.1.2 will for the most part be ok. Some of these below 200 kV lines will have to be
reconstructed to be able to have adequate protection and meet the required loadability. It will be difficult to do this in 39
months. We suggest a mitigation program be required for those lines that will be difficult to meet the 39 month deadline.
Yes
No

No
Several parts of the standard go too far (Appendix A R1.10) and will require us to document faults and clearing times to
prove the fault duty of transformer connections. Also the requirements to deal with out of step blocking relays should go in
phase 3 and not in this standard.
: Utilities with long lines and in weak areas will have difficulty protecting their lines and meeting the required loadability.
Regions where there are very rural systems will want to write standards that allow adequate protection for their systems.
No
Group
FirstEnergy
Doug Hohlbaugh
Yes
Yes
No
Although it is true that the FERC directive specifically states "limiting piece of equipment" their reasons and justifications
all involve transformers. We propose replacing "limiting piece of equipment" with "transformer" would meet the FERC's
reliability concern as well as provide clarity to applicable entities. We believe this is an equally effective means of meeting
the directive.
No
We suggest removing the Regional Entity from the list of entities receiving this information since they do not have a
reliability-related need for it.
Yes
Yes
Although we agree that R5 is the appropriate requirement to reference the criteria to be used, it is still to be determined if
we agree with the criteria since it is still being developed.
No
FirstEnergy supports applying PRC-023 to certain supervising relays, such as overcurrent relays that are enabled only
when another (usually communications based) scheme is out of service, or overcurrent relays that are ANDed with current
differential elements that can trip by themselves if the communications path used by the current differential scheme is
compromised. However, it is not clear that a 150% factor is the correct one to use in this case. Our understanding is that
150% is a combination of an error factor (widely utilized by industry) of 15% plus a 35% margin to approximate a 15
minute interval rating to give operators time to react to adverse system conditions. It is unclear that this extra 35% margin
is needed for these supervising relays, when the reliability goal is to prevent relays being continuously picked-up. We
recommend that the standard utilize a 115% margin (rating duration nearest 4 hours) for these types of supervising relays
and that this would be adequate to meet the Commission's stated reliability concerns. However, there are several other
types of schemes that utilize supervising relays where applying PRC-023 would be detrimental to the reliability of the bulk
power system. One widely used case is the supervision of an impedance relay when there is no communications scheme
involved. There are cases where an impedance element/relay which is set per PRC-023, correctly operates for a fault it is
intended to see, but that the actual current value will be on the order of the line rating, which will result in the scheme not
operating if the supervising relay is set as the commission proposes. The alternative for these types of schemes is to
remove the supervision from the scheme, which will result in the scheme operating purely on the impedance element,
which is exactly the reliability concern that the Commission is trying to address with this directive. However, many
microprocessor relays have inherent overcurrent supervision of impedance elements which cannot be disabled, adding to
the complexity of the issue. Since this is a fairly complex theoretical/technical issue, we recommend that the NERC
System Protection and Control Subcommittee (SPCS) investigate this issue and produce a white paper or other document
describing any unintended consequences of implementing the FERC directive. The work of the SPCS could also consider
equally effective alternatives to meeting the Commission’s directive.
Yes
No
i. The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011. However, this
directive should be included in Phase III since it deals with the subject of relay operations due to power swings. ii. The
directive from P. 224 is missing from the detailed section of the SAR, but is included in the table in the back of the SAR. iii.
As mentioned in our response to Question 7, we do not agree with how the project is proposing to address the P. 264
directive.
No
Regarding the direcive of Par. 264, since this is a fairly complex theoretical/technical issue, we recommend that the NERC
System Protection and Control Subcommittee (SPCS) investigate this issue and produce a white paper or other document
describing any unintended consequences of implementing the FERC directive. The work of the SPCS could also consider
equally effective alternatives to meeting the Commission’s directive.
Yes
We agree that this standards action is necessary to meet the FERC directives, but have some concerns as we have stated

in previous responses above.
No
No
Group
TSGT System Planning Group
Bill Middaugh
Yes
No
We suggest that the added phrase be removed from R1 and a new requirement created. Suggested wording is “Protection
Systems that block for stable swings or out-of-step conditions shall be evaluated to ensure that appropriate tripping will
occur for in-section faults that occur during the condition. Some additional delay may be required and is acceptable to
ensure that the appropriate tripping occurs.”
Yes
No
We think that the data needs to be given only to the Transmission Operators, which is what FERC Order No. 733 requires.
We also believe that an initial submittal is sufficient until any responsible entity begins or stops using Requirement 1,
Setting 2 for setting a phase protective relay that is used to protect an applicable facility. There is no need for periodic
duplicate submittals.
No
FERC Order No. 733 requires the settings be provided upon request and no initial or periodic submittal is required.
No
While we agree that the purpose of Requirement R5 is beneficial, there is much confusion about registration and
responsibilities of Planning Coordinators. Though the FERC order proposes that planning coordinators perform the test
developed herein, there is also flexibility in how NERC can achieve the same result. We believe that the Regional Entity
(or the Reliability Coordinator, as was included in the System Protection and Control Task Force recommendation) should
be the responsible functional entity for determining which elements operated at less than 200 kV need to meet
Requirement R1. The Region was responsible for determining operationally significant facilities during the “Beyond Zone
3” process.
Yes
As we interpret the changes to Attachment A they are acceptable. However, there appears to be uncertainty about the
intent of the drafting team. We interpret the change to 1.6, in conjunction with 2.1, to allow setting impedance relay fault
detector supervisory elements at levels below load current levels. This understanding comes from the realization that the
fault detector elements by themselves do not “trip with or without time delay, on load current,” a requirement described in
1. The fault detector elements can cause tripping on their own, but only for conditions of loss of potential or loss of
communications, which are both excluded from the loadability requirements as steted in 2.1. If Tri-State’s interpretation of
the intent of Attachment A, Sections 1, 1.6, and 2.1 is incorrect, then we do not agree that this is an acceptable and
effective method of meeting this directive. There are many protection system locations in our system that require the fault
detector supervision elements to be set below load current levels in order for backup impedance relays to operate
securely in the event of loss of potential and to operate dependably for remote faults that inherently have low fault current
magnitudes.
Yes
No
As stated in our earlier comments, we believe that some proposals exceed the directives. It is also not clear how p 162
was addressed in PRC-023-2 as indicated on SAR-3.
Yes
We included specific proposals in our comments to questions 2, 4, 5, and 6.
Yes
We agree that the scope meets the FERC directive, but some of the proposals in the proposed standard reach beyond the
directive.
No
No
Individual
Yes
Yes
Yes

Yes
Yes
Yes
No
Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open breakers will be
needed for loss of potential conditions. The corollary would be leaving the element in service with fast tripping enabled for
a fault until the loss of potential condition can be diagnosed and corrected.
Yes
Yes
No
No
Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open breakers will be
needed for loss of potential conditions. The corollary would be leaving the element in service with fast tripping enabled for
a fault until the loss of potential condition can be diagnosed and corrected.
No
No
Individual
Laura Zotter, Steve Myers
ERCOT ISO

The entities who receive the list of facilities should be the same from R3 to R4.
The entities who receive the list of facilities should be the same from R3 to R4.
No
ERCOT ISO respectfully asserts that the changes in this standard need more thorough discussion. This standard is
incomplete without the Attachment B and the intent of the requirements is not explicitly clear. A standard drafting team
(not a SAR SDT) needs to develop Attachment B through discussion of the entire process that will meet Order 733
directives. Attachment B is a critical component needed to assess R5 and provide further feedback. Requirement 5 needs
to be reworded for clarity. The standard drafting team assigned to this project needs to work closely with the Reliability
Coordination SDT (Project 2006-06), which is tasked with defining critical facilities or identifying criteria for developing a
list of critical facilities. ERCOT ISO disagrees with the use of the phrase ‘facilities that are critical’ in this requirement. A
requirement to create a list of critical facilities should not be addressed in this standard.

ERCOT ISO thinks a standard drafting team can evaluate the Order 733 directives, work in conjunction with other
Standard Drafting Teams already addressing some aspects of critical facilities, may be able to more succinctly arrive at an
equally efficient and effective method of achieving the intent of the directive(s). The coordination between teams is vital to
avoid confusion and possible overlap.

Individual
RoLynda Shumpert
South Carolina Electric and Gas

No
This requirement needs to be refined to clearly state the intent. It is unclear if “limiting piece of equipment” is referring to
just transformers or other elements. Some of the elements involved in the construction of a transmission line/transformer
arrangement such as line conductors, etc. may not have published fault current ratings. It is unclear how to determine the
most limiting piece of equipment if published fault current ratings are not available for these devices

No
Item 1.6 of Attachment A needs to be clarified. If the intent is to include protective functions such as fault detectors then
this could possibly lead to relay sensitivity problems when switching contingencies create weaker systems than normal
and a line is faulted. It is unclear why supervisory functions are considered if the protective functions they supervise will
operate in compliance with R1

Individual
Jon Kapitz
Xcel Energy
Yes
Yes
Yes
Yes
Yes
Yes
No
Xcel Energy disagrees with the inclusion of the supervising functions in part 1.6 of Section 1 in Attachment A. Supervising
functions in protection schemes provide security for non-power system fault events and are not the principal elements for
scheme operation. Only principal elements should be considered in the requirements of the PRC-023 standard. Functions
such as overcurrent fault detectors provide security in the event of a failed potential source or blown secondary fusing.
Fault detectors must be set below the minimum end-of-zone fault with a single system contingency in effect. It is common
industry practice to set these functions at 60-80% of these minimum fault levels and may necessitate a setting that is
below the Facility Rating of a circuit. Increasing the setpoint of an overcurrent fault detector above the Facility Rating will
limit the coverage of the protection system and may impact the system’s ability to protect the electrical network from
Faults. An alternative is to limit the Facility Rating as allowed in Requirement R1.12. However limiting this Facility Rating
places an arbitrary constraint on the circuit and is not justifiable for a non-principal function. Eliminating the fault detector is
not possible in the case of some microprocessor-based relays and if it is possible, reduces the security of the protective
scheme.
Yes

Group
IRC Standards Review Committee
Ben Li
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
Some immediate concerns with the proposal include: 1) It is not clear what a “critical facilities list identified by the Regional
Entity” is as specified within the order so addressing the directive is a challenge. This standard is not the appropriate
venue for development or consideration of a critical facilities list. There is a supplemental SAR in process for the Reliability
Coordination project that is to address that topic. 2) Our understanding is that the application of NERC standards is limited
to the BES. Thus, facilities below 100 kV must be included in the Regional Entity definition of BES to be eligible. The
requirements should reflect this. The way the proposed standard reads, one might conclude the PC must test every facility
below 100 kV. This surely can’t be the intent. 3) Furthermore, the directive appears to require some action on the Regional
Entities. From paragraph 60, “We also direct that additions to the Regional Entities’ critical facility list be tested for their

applicability to PRC-023-1 and made subject to the Reliability Standard as appropriate.” It is not clear how this directive is
reflected in the standard to ensure that this work is completed prior to the PC’s performing their assessment for below 200
kV facilities. This standard is not the appropriate venue to determine or revise a critical facilities list, nor is it appropriate for
a Regional Entity to establish such a list. The bottom line is that the changes here are significant enough that they would
benefit from a group of experts reviewing the directives and proposing the precise language that is needed.
No
We believe this directive needs to be addressed by a standards drafting team to ensure the precise language is crafted to
adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
Additionally, we question if this directive should be addressed in the FAC standards rather than in PRC-023.
No
We do not understand the need for this directive or requirement. A relay that is set to operate at 115% greater than the 15minute rating of the facility does not equate to damage occurring on that facility if operated at that point in 15 minutes.
Furthermore, it does not mean the relay will operate in 15 minutes nor does it mean the operator has only 15 minutes to
take action. In fact, the operator may have less time depending on the time delay set on the relay. It is no different than
any other relay. Usually, the facility will be operated with some buffer so that there is no chance that an entity could trip the
facility due to loading above the relay limit. In fact, the transmission operator should be aware of any relay that might be
the limiting facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.
No
The objective of R4 as written is unclear and does not conform with the results-based concept in that it does not clearly
specify a reliability directive. We suggest removing this requirement altogether as we do not believe this should be an ongoing enforceable requirement. Rather, we think it makes more sense for NERC to use section 1600 of its Rules of
Procedure to request the data. We believe that NERC and the Commission will likely determine that they don’t need to
continually receive this data after reviewing it the first time. Nothing in the directive indicates this must be accomplished
through a standard. If NERC and FERC do identify a continuing need for the data, the standard could be modified at a
later date.
No
We disagree with modifying the requirement until the criteria is identified. Modifying the requirement now presumes the
criteria will have no impact to the requirement. Contrarily, we believe that the criteria may cause some change to the
requirement as well. The criteria in Attachment B along with any necessary modifications to the associated requirement
should be developed by a full standards drafting team. Only the full standards drafting team could identify equally effective
alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
No
We believe this directive needs to be addressed by a full standards drafting team to ensure the precise language is crafted
to adequately address the directive. Furthermore, we believe only the full standards drafting team could identify equally
effective alternatives to the Commission’s directives as they have made clear they allow in this Order and many others.
No
While we agree removing the footnote is straight forward and addresses one Commission directive, we believe the other
directives need to be addressed by a full standards drafting team to ensure the precise language is crafted to adequately
address the directives. Furthermore, we believe only the full standards drafting team could identify equally effective
alternatives to the Commission’s directives as they have made clear they allow in this Order and many others. In
particular, we believe that only a full drafting team could adequately assess if any additional time will be needed to comply
with the standard for sub-100 kV facilities particularly when we consider there are some outstanding issues including a
regional entity’s critical facilities list identified in Question 1. Also, we are unable to assess if the two directives are fully
addressed absent a proposed implementation plan.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that the scope be
modified to make clear that the drafting team may use equally effective alternatives to address the Commission’s
directives per the Commission in this order and other orders such as Order 693. There is a discrepancy between the
entities listed in the Applicability Section and those checked off in the SAR. The latter indicates that the SAR is also
applicable to the Reliability Coordinator, which we do not believe is appropriate.
No
We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is the purpose
for convening a full drafting team and that the drafting team should propose their alternatives.
No
We largely believe the scope will allow the drafting team to address the directives. However, we request that the scope be
modified to make clear that the drafting team may use equally effective alternatives to address the Commission’s
directives per the Commission in this order and other orders such as Order 693.
No
We are not aware of any regional variances per se. However, each regional entity has its own definition for BES and this
needs to be considered when addressing sub-100 kV facilities.
No

Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
No
However, this response is conditional depending on whether the criteria that will be established within Attachment B (see
R5.1) are reasonable and apply to properly qualified facilities below 200 kV.
Yes
No
The word change meets the strict interpretation of the directive, but it is not necessarily improving the reliability of the
system. Faults are cleared in cycles and transformer damage curves do not start until at least one second.
Yes
No
While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.
No
As noted in Q1 above, a response would be conditional and depend on whether the criteria that will be established within
Attachment B (see R5.1) are reasonable and apply to properly qualified faculties below 200 kV. In addition, the R5
requirement should include wording that limits the scope of the transmission facilities (line and transformer circuits) to be
evaluated to only those transmission facilities that can be tripped by the relay settings subject to requirement R1.
Requirement R5 should also qualify that only the transmission facilities that are “known” to be associated with the relay
settings subject to requirement R1 need to be evaluated. If the SDT wants to better assure that the Planning Coordinator
knows about all of the pertinent transmission facilities, then they should add a requirement that obligates Transmission
Owners, Generator Owners, and Distribution Providers to provide the Planning Coordinator with a list of the transmission
facilities that are associated with the relay setting subject to requirement R1.
No
In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two components
of reliability for protective relays. The Commission did not recognize that the two tend to be mutually exclusive. Raising
dependability (making sure breakers trip during a fault) can sacrifice some degree of security (tripping more than is
needed). Historically, protection engineers have been biased toward dependability to ensure the safety of people and
equipment. The exclusions allow that to happen. These are contingency scenarios where protective schemes are
compromised. For a second contingency, the dependability is at risk if fast tripping is not employed. By removing the
exclusion, reliability could be negatively jeopardized. For example, an operational decision to open breakers will be
needed for loss of potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until
the loss of potential condition can be diagnosed and corrected.
Yes
No
It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.
Yes
On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the inclusion of
qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities that are not tripped by the
applicable relay settings).
No
We agree that the topics of generator relay loadability and power swing protective relaying should be referred to in other
separate standards. While we acknowledge that it is in everyone’s best interest to respond to the FERC directives, there
are numerous technical flaws that need to be resolved in their request. Forming a team and spending considerable
resources will not gain industry acceptance to these directives.
No
No
Group
Dominion Electric Market Policy
Mike Garton
No
It depends on what Attachment B (R5.1) requires once it is developed. Without knowledge of the final content developed
for Attachment B, we do not support this.
Yes
No
The requirement is not clear. For example, how do we determine and verify the limiting piece of equipment under fault
conditions? It might be a splice or a jumper. Since the document refers to duration, this seems to apply mainly to

transformer overcurrent relaying which would be for overload protection not fault protection that has no intentional delay.
Yes
Yes
Yes
No
Dominion disagrees with the directive to the ERO to revise section1 to include supervising relays for example, the fault
detectors that we have in electromechanical distance schemes. The impedance relays are set to meet Reliability Standard
PRC-023-1 while the overcurrent fault detector does not trip the transmission line breaker(s) independently of the
impedance relays. Simultaneously meeting full allowance of the line terminal emergency loading limit and providing
adequate sensitivity for detecting line faults with this fault detector will simply not be achievable for many of our lines.
Yes
Yes
No
Yes
No
No
Since there is no question that asks if there are other concerns with this draft, I will add one here….. R2 should be
modified to read “ The Each Transmission Owner, Generator Owner, or and Distribution Provider that uses a circuit
capability with the practical limitations described in Requirement R1, Settings1.6, R1.7, R1.8, R1.9, R1.12, or R1.13 shall
use the calculated circuit capability as the Facility Rating of the circuit and shall forward this information to the Planning
Coordinator, Transmission Operator, and Reliability Coordinator. The burden for acknowledging agreement or specifying
reasons for disagreement should reside with the Planning Coordinator, Transmission Operator, and Reliability
Coordinator. Suggest SDT develop additional requirements similar to those in FAC-008 @ R2 and R3.
Individual
Greg Rowland
Duke Energy
Yes
Yes
No
R1.10 has added the requirement that protection settings can’t expose transformers to fault levels and durations that
exceeds its capability, while at the same time not operate at or below 115% of highest emergency rating. We would argue
that an overcurrent relay cannot be set to satisfy both requirements. A transformer’s through-fault protection curve
(C37.91) begins at 200% of the transformers self-cooled rating. The highest emergency rating is commonly 150% (or
higher) of the transformer’s highest (cooled) rating. Overcurrent relays could not be set to coordinate with both the
damage curve and the overload rating.
Yes
Yes
Paragraph 224 addresses R1.12, requiring documentation and making available a list of facilities that have protective
relays set pursuant to R1.12. Although Order 733 was silent on R1.13, should the new R4 not also apply to R1.13?
No
We don’t have Attachment B yet, and the standard development timeline has the standard being submitted to FERC in
March of 2011, which we believe is an unreasonable timeline.
No
Attachment A has added 1.6 stating “Protective functions that supervise operation of other protective functions” is included
in the standard. We would argue that it is not reasonable to include overcurrent fault detectors used to supervise distance
elements or breaker failure schemes. These relays provide security to the protection scheme, such as for loss of potential
conditions, and do not trip on their own. If these relays would be set per the standard, it would render the schemes
ineffective for many fault conditions. In the case of electromechanical schemes, the supervising relay could be removed
from service which could make the protection scheme misoperate. In the case of microprocessor relays, the supervising
relay is embedded in logic and can’t be removed.
No
Until we see the criteria for Attachment B, we can’t agree that 39 months is sufficient time.

Yes
No
No
• The SAR states that Paragraph 162 is part of Phase I, but the new standard addressing stable power swings is Phase III.
No
No

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR
and an initial set of proposed requirements — Project 2010-13
The Revisions to Relay Loadability for Order 733 SAR Drafting Team thanks all commenters
who submitted comments on the proposed SAR and an initial set of proposed requirements.
The SAR and proposed standard were posted for a 30-day public comment period from
August 19 through September 19, 2010. The stakeholders were asked to provide feedback
on the standards through a special Electronic Comment Form. There were 36 sets of
comments, including comments from more than 88 different people from approximately 36
companies representing 8 of the 10 Industry Segments as shown in the table on the
following pages.
The Standard was posted for an “informal” comment period – the team provided a summary
responses to the comments submitted on the proposed standard (Questions 1-8) and the
SAR was posted for a “formal” comment period - and the team provided detailed responses
to the comments submitted on the SAR (Questions 9-13)

Summary of Changes:

The SDT revised sections 4.1.2 and 4.1.4 for consistency and to refer to facilities “determined by
the Planning Coordinator to comply with this standard.”
The SDT added a new 4.1.3 “Transmission lines operated below 100 kV that Regional Entities
have identified as critical facilities for the purposes of the Compliance Registry and are also
determined by the Planning Coordinator as required to comply with this standard. "
The SDT renumbered old 4.1.3 to 4.1.4.
The SDT renumbered old 4.1.4 to 4.1.5 and reverted the voltage threshold to the original text
consistent with the modification to section 4.1.2.
The SDT added "4.1.6 Transformers with low voltage terminals connected below 100 kV that
Regional Entities have identified as critical facilities for the purposes of the Compliance Registry
and are also determined by the Planning Coordinator as required to comply with this standard."
In response to comments that Requirement R5 is confusing the SDT deleted “to prevent
cascading when protective relay settings limit transmission loadability” from Requirement R5.
Removing this does not change the intent of the requirement.
Commenters indicated for a variety of reasons that the requirement related to out-of-step
blocking added to Requirement R1 is confusing. The SDT agrees and removed out-of-step
blocking from Requirement R1. The requirement pertaining to evaluation of out-of-step
blocking protection has been moved to a separate requirement (now Requirement R2) to more
clearly delineate this requirement from assessment of relay loadability of phase protective relays.
Some commenters indicated that the word “settings” should be replaced throughout R1 when
referring to a part, or sub-requirement of R1. The SDT modified Requirement R1 by replacing
the word “settings” with “criteria.” This is consistent with the main Requirement R1 which in
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609.452.8060 | www.nerc.com

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13

the presently approved standard (PRC-023-1) refers to sub-requirements R1.1 through R1.13 as
criteria to prevent phase protective relay settings from limiting transmission system loadability.
Some commenters identified an error in the draft standard in criterion 9 in Requirement R1 that
resulted in omitting a phrase contained in the presently approved standard. The SDT modified
criterion 9 in Requirement R1 to reinsert the deleted phrase.
IEEE C37.91 Figure A5 has two components to the thermal damage curve for through-faults: the
“thermal component” begins at 2x the transformer nominal nameplate rating, and seems to be the
root of commenters’ concerns. The “mechanical component” begins at a current equal to the
reciprocal of the twice the transformer impedance. The commenters are correct in their
characterization of the “thermal component” of the transformer damage curve, in that it is not
possible to satisfy the posted PRC-023-2 R1, criterion 10 and also protect the transformer for
currents in this region. Upon careful consideration of FERC Order 733, the SDT revised R1
criterion 10 to reference only the mechanical withstand capability.
Many commenters questioned the inclusion of “limiting piece of equipment” rather than
“transformer”, as the fault-withstand capability of terminal equipment (switches, breakers,
current transformers, etc) may be unavailable. Upon further consideration of FERC Order 733,
the SDT modified criterion 10 by replacing “limiting equipment” with “transformer.”
The SDT modified the wording of R4 as follows. "Each Transmission Owner, Generator Owner,
and Distribution Provider that chooses to utilize Requirement R1 criterion 2 as the basis for
verifying transmission line relay loadability shall provide....” as a result of comments.
The SDT agreed to remove the Regional Entity from the list of entities receiving this information
in Requirement R4.
One commenter noted that the SDT needs to work closely with the Reliability Coordination SDT
(Project 2006-06) which is tasked with defining critical facilities or indentifying criteria for
developing a list of critical facilities. The commenter disagreed with use of the phrase “facilities
that are critical” in this requirement and cautioned that a requirement to create a list of critical
facilities should not be addressed in this standard. The SDT notes that although the phrase
“critical to reliability of bulk electric system” appears in the approved PRC-023-1 and is used in
Order No. 733, the SDT recognizes that use of the same or similar terms in multiple standards
will result in confusion. Use of the phrase “critical to reliability of the Bulk Electric System” in
PRC-023 is intended to have meaning specific to the issue of relay loadability; specifically to
identify facilities, that if they trip due to relay loadability following an initiating event, may
contribute to undesirable system performance similar to what occurred during the August 2003
blackout. The SDT has modified the standard to replace the phrase “critical to the reliability of
the bulk electric system” with “that must comply with this standard.” The SDT believes this will
avoid potential confusion and that reliability will be adequately addressed because the criteria in
PRC-023 - Attachment B identify all facilities that must be subject to this standard to maintain
reliability of the Bulk Electric System.
One commenter noted that Requirement R5, Part 5.1 is unnecessary since the process to use the
criteria in PRC-023 - Attachment B would almost certainly be to simply apply the criteria and
November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13

that requiring documentation of such a process will result in increased paperwork and additional
preparation for an audit without a reliability benefit. The SDT agrees that this part of
Requirement R5 is unnecessary and has removed it from the Standard.
Three-fourths of commenters believe the addition of section 1.6 in PRC-023 - Attachment A is
not an equally efficient and effective method of meeting this directive. More than one-half of
commenters believe that addressing the directive in the proposed manner will have a negative
impact on reliability of the bulk electric system. The SDT agrees that addressing the directive in
the manner proposed in the first posting will have the unintended consequence of impacting the
dependability and security of certain protection systems. The SDT has revised the draft standard
to address the following concerns noted by commenters.
•
More than one-half of commenters noted that the proposed modification would
require overcurrent fault detectors applied to supervise distance (impedance) elements to
meet the relay loadability requirements which would have a detrimental impact on
reliability. Setting these fault detectors to meet PRC-023 would restrict the ability of
some distance elements to trip for end-of-zone faults, particularly on weak source
systems. Eliminating the fault detector to avoid this concern would have the negative
impact of making the protection system susceptible to undesired tripping during close-in
faults on adjacent elements. Some commenters further noted that many microprocessor
relays have inherent overcurrent supervision of impedance elements which cannot be
disabled.
•
Several commenters noted that the standard should apply to protective systems
and not to individual components of protective systems and that compliance should be
based on the ability of the protective system as a whole to meet the performance criteria
established by the standard. Some commenters also noted that a clarification is required
that “protective functions” applies only to those protective relay elements that would
respond to non-fault or load conditions and could issue a direct trip.
•
Some commenters noted their belief that the modification goes well beyond the
Commission’s concern and they proposed alternatives they believe would be equally
effective and efficient approaches to addressing the Commission’s reliability concerns.
In response to these concerns, in particular the negative impact on reliability associated with the
proposed modification, the SDT has modified section 1.6 to include “1.6. Supervisory elements
associated with current based communication assisted schemes where the scheme is capable of
tripping for loss of communications.” The SDT also modified the second bulleted item in
section 2.1 to add the clause, “except as noted in section 1.6 above.”
The SDT agrees with several commenters about the proposed language for Effective Dates and
has changed the language to the following:
5.1.
Requirement R1: the first day of the first calendar quarter after applicable regulatory
approvals, except as noted below.
5.1.1 For the addition to Requirement R1, criterion 10, to set transformer fault
protection relays and transmission line relays on transmission lines terminated only with a
November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13

transformer such that the protection settings do not expose the transformer to fault level and
duration that exceeds its mechanical withstand capability, the first day of the first calendar
quarter 12 months after applicable regulatory approvals.
5.1.2 For supervisory elements as described in Attachment A, section 1.6, the first day
of the first calendar quarter following 24 months after applicable regulatory approvals.
5.2.
Requirements R2 and R3: the first day of the first calendar quarter after applicable
regulatory approvals.
5.3.
Requirements R4 and R5: the first day of the first calendar quarter following 24 months
after applicable regulatory approvals.
5.4.
Requirement R6: the first day of the first calendar quarter 18 months after applicable
regulatory approvals.
5.5.
Requirement R7: the first day of the first calendar quarter after applicable regulatory
approvals.
To address the need for entities to meet the requirements of the standard for facilities identified
by the Planning Coordinator in the future, the SDT added a new requirement (R7).
Several commenters indicated that the directive from P. 224 is missing from the detailed section
of the SAR, but is included in the table in the back of the SAR. This was an error in the SAR and
the SDT has added this directive to the detailed section of the SAR for Phase I. The new
Requirement R5 will support collection of the data necessary for the ERO to address the
directive. The ERO will provide the data upon request, but outside of PRC-023.
http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is
to give every comment serious consideration in this process! If you feel there has been an error
or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at
609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability
Standards Appeals Process.1

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

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of
proposed requirements — Project 2010-13

Index to Questions, Comments, and Responses
1.

The Applicability Section (4.1.2 and 4.1.4) and Requirement R5 (previously Requirement R3) have
been modified to address the directive in Paragraph 60 of Order no. 733. Do you agree that this is
an acceptable and effective method of meeting this directive? If not, please explain. ..................... 13

R1 has been modified to address the directive in Paragraph 244 of Order no. 733. Do you agree
that this is an acceptable and effective method of meeting this directive? If not, please explain. .... 19

Requirement R1, setting 10 has been modified to address the directive in Paragraph 203 of Order
no. 733. Do you agree that this is an acceptable and effective method of meeting this directive? If
not, please explain. ........................................................................................................................... 25

Requirement R3 has been added to address the directive in Paragraph 186 of Order no. 733. Do
you agree that this is an acceptable and effective method of meeting this directive? If not, please
explain. .............................................................................................................................................. 29

Requirement R4 has been added to address the directive in Paragraph 224 of Order no. 733. Do
you agree that this is an acceptable and effective method of meeting this directive? If not, please
explain. .............................................................................................................................................. 33

Requirement R5 and part 5.1 (previously Requirement R3 and part 3.1) have been modified to
establish the framework to address the directive in Paragraph 69 of Order no. 733, although the
criteria itself (which will be Attachment B) is still being developed. Do you agree that this is an
acceptable and effective method of meeting this directive considering that Requirement R5 is
establishing the construct to insert the criteria at a future time in the form of Attachment B? If not,
please explain. .................................................................................................................................. 37

Attachment A has been modified to address the directive in Paragraph 264 of Order no. 733. Do
you agree that this is an acceptable and effective method of meeting this directive? If not, please
explain. .............................................................................................................................................. 44

Do you agree that the SDT has addressed the remaining directives: Paragraph 284 to remove the
footnote and Paragraph 283 to modify the implementation plan for sub-100 kV facilities (by revising
the Effective Date section of the standard)? ..................................................................................... 54

Do you agree that the scope of the proposed standards action addresses the directive or
directives? ......................................................................................................................................... 58

10.

Can you identify an equally efficient and effective method of achieving the reliability intent of the
directive or directives? ....................................................................................................................... 63

11.

Do you agree with the scope of the proposed standards action? ..................................................... 68

12.

Are you aware of any regional variances that we should consider with this SAR? .......................... 74

13.

Are you aware of any associated business practices that we should consider with this SAR? ........ 78

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

Guy Zito

Northeast Power Coordinating Council

Additional Member Additional Organization Region Segment Selection
1. Alan Adamson

NY State Reliability
Council

NPCC 10

2. Gregory Campoli

NY Independent
System Operator

NPCC 2

3. Kurtis Chong

Independent Electricity
System Operator

NPCC 2

4. Sylvain Clermont

Hydro-Quebec
TransEnergie

NPCC 1

5. Gerry Dunbar

NPCC

NPCC 10

Utility Services

NPCC 7

7. Dean Ellis

Dynegy Generation

NPCC 5

8. Brian L. Gooder

Ontario Power
Generation

NPCC 5

Brian EvansMongeon

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

9. Kathleen Goodman ISO New England

NPCC 2

10. Chantel Haswell

FPL Group Inc

NPCC 5

11. David Kiguel

Hydro One Networks

NPCC 1

Northeast Utilities

NPCC 1

13. Randy MacDonald

New Brunswick System
Operator

NPCC 2

14. Bruce Metruck

NY Power Authority

NPCC 6

15. Lee Pedowicz

NPCC

NPCC 10

16. Robert Pellegrini

The United Illuminating
Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec
TransEnergie

NPCC 1

18. Saurabh Saksena

National Grid

NPCC 1

19. Michael Schiavone

National Grid

NPCC 1

20. Peter Yost

Consolidated Edison of
New York

NPCC 3

Dominion Resources

NPCC 5

12.

Michael R.
Lombardi

21. Mike Garton

Group

Richard Kafka

Additional Member

Additional
Organization

Pepco Holdings, Inc - Affiliates
Region

1, 3, 5, 6

Segment
Selection

1. Alvin Depew

Potomac Electric Power
RFC
Company

2. Carl Kinsley

Delmarva Power & Light
RFC
Company

3. Evan Sage

Potomac Electric Power
RFC
Company

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

4. Rob Wharton

Group

Atlantic City Electric

Kenneth D. Brown

RFC

PSEG Power

RFC

2. Jim Hebson

PSEG ER &T

NPCC

3. Scott Slickers

PSEG Connecticut

NPCC

4. Jerzy Slusarz

Odessa power Partners

ERCOT

5. Jim Hubertus

PSEG

RFC

1,3

Denise Koehn

Bonneville Power Administration

Additional Member Additional Organization Region
1. Dean Bender

Group

BPA

Doug Hohlbaugh

WECC

Group

Ben Li

1, 3, 5, 6

1, 3, 4, 5, 6

Segment
Selection
1, 3, 4, 5, 6

IRC Standards Review Committee

Additional Member Additional Organization Region

Segment
Selection

1. Bill Phillips

MISO

MRO

2. Patrick Brown

PJM

RFC

3. James Castle

NYISO

NPCC

November 1, 2010

FirstEnergy

RFC

Segment
Selection

Additional Member Additional Organization Region
1. Sam Ciccone

Segment
Selection

1. Dave Murray

Group

PSEG Companies

Additional Member Additional Organization Region

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

4. Greg Van Pelt

CAISO

WECC

5. Charles Yeung

SPP

6. Steve Myers

ERCOT

7. Mark Thompson

AESO

WECC

Group

Carol Gerou

MRO's NERC Standards Review
Subcommittee

Additional Member Additional Organization Region
Omaha Public Utility
District

MRO

1,3,5,6

2. Chuck Lawrence

American Transmission
Company

MRO

3. Tom Webb

WPS Corp

MRO

3,4,5,6

4. Jason Marshall

Midwest ISO

MRO

5. Jodi Jenson

Western Area Power
Admin.

MRO

1,6

6. Ken Goldsmith

Alliant Energy

MRO

7. Dave Rudolph

Basin Electric Power
Cooperative

MRO

1,3,5,6

8. Eric Ruskamp

Lincoln Electric System

MRO

1,3,5,6

9. Joseph Knight

Great River Energy

MRO

1,3,5,6

10. Joe DePoorter

Madison Gas & Electric

MRO

3,4,5,6

11. Scott Nickels

Rochester Public Utilities MRO

12. Terry Harbour

Mid American Energy
Co.

1,3,5,6

November 1, 2010

Segment
Selection

1. Mahmood Safi

MRO

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

Mike Garton

Dominion Electric Market Policy

Additional Member Additional Organization Region

Dominion Resource
Services

NPCC

2. Louis Slade

Dominion Resource
Services

SERC

1, 3, 5, 6

Individual

Brent Ingebrigtson

E.ON U.S. LLC

10.

Individual

William Gallagher

Transmission Access Policy Study Group

Individual

Jana Van Ness, Director
Regulatory Compliance

Arizona Public Service Company

12.

Individual

Andrew Z. Pusztai

American Transmission Company

13.

Individual

Sandra Shaffer

PacifiCorp

14.

Individual

Andy Tillery

Southern Company

15.

Individual

Bill Middaugh

TSGT System Planning Group

16.

Individual

Gene Henneberg

NV Energy

17.

Individual

Steve Wadas

NPPD

18.

Individual

Joylyn Faust

Consumers Energy

19.

Individual

Jonathan Meyer

Idaho Power - System Protection

November 1, 2010

Segment
Selection

1. Michael Gildea

11.

X
X

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Individual

Michael Gammon

Kansas City Power & Light

21.

Individual

Dan Rochester

Independent Electricity System Operator

22.

Individual

Bill Miller

ComEd

23.

Individual

Kasia Mihalchuk

Manitoba Hydro

24.

Individual

Brian Evans-Mongeon

Utility Services

25.

Individual

Tribhuwan Choubey

Southern California Edison

26.

Individual

Dale Fredrickson

Wisconsin Electric

27.

Individual

Kathleen Goodman

ISO New England Inc.

28.

Individual

Robert Ganley

Long Island Power Authority

29.

Individual

Kirit Shah

Ameren

30.

Individual

Thad Ness

American Electric Power

31.

Individual

Michael Moltane

ITC Holdings

32.

Individual

Not indicated

Not Indicated

Individual

Laura Zotter, Steve
Myers

ERCOT ISO

Individual

RoLynda Shumpert

South Carolina Electric and Gas

34.

November 1, 2010

20.

33.

X
X

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

35.

Individual

Jon Kapitz

Xcel Energy

36.

Individual

Greg Rowland

Duke Energy

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
1. The Applicability Section (4.1.2 and 4.1.4) and Requirement R5 (previously Requirement R3) have been modified to address the
directive in Paragraph 60 of Order no. 733. Do you agree that this is an acceptable and effective method of meeting this directive? If
not, please explain.

Summary Consideration:
Several commenters wanted to know what is meant by “critical to the reliability of the Bulk Electric System (BES)”. The SDT notes that although
the phrase “critical to reliability of bulk electric system” appears in the approved PRC-023-1 and is used in Order No. 733, the SDT recognizes that
use of the same or similar terms in multiple standards will result in confusion. Use of the phrase “critical to reliability of the Bulk Electric System” in
PRC-023 is intended to have meaning specific to the issue of relay loadability; specifically to identify facilities, that if they trip due to relay
loadability following an initiating event, may contribute to undesirable system performance similar to what occurred during the August 2003
blackout. The SDT has modified the standard to replace the phrase “critical to the reliability of the bulk electric system” with “that must comply
with this standard.” The SDT believes this will avoid potential confusion and that reliability will be adequately addressed because the criteria in
Attachment B identify all facilities that must be subject to this standard to maintain reliability of the Bulk Electric System.
Several commenters indicated that the phrase "low voltage terminals" is open to interpretation. This term is part of the existing standard and not
included in the scope of the SAR; however, Attachment B will clarify the criteria to determine which facilities must comply with the standard.
The SDT revised sections 4.1.2 and 4.1.4 for consistency and to refer to facilities “determined by the Planning Coordinator to comply with this
standard.”
Commenters indicated that they did not believe the standard should apply to facilities below 100 kV; however, in Order 733, NERC was directed to
apply PRC-023 to facilities below 100 kV, as well as 100 kV to 200 kV, and to provide criteria to establish which of those facilities to which PRC023 was to apply. As noted with this posting, the criteria was posted for public comment and is intended to be included with the next posting of
this standard.
Commenters indicated that they did not believe the standard should apply to facilities below 100 kV; however, in Order 733, NERC was directed to
apply PRC-023 to facilities below 100 kV, as well as 100 kV to 200 kV, and to provide criteria to establish those facilities to which PRC-023 was to
apply. As noted with this posting, the criteria were posted for public comment and will be included with the next posting of this standard.
Commenters were reluctant to offer a firm response to the proposed modifications without reviewing the proposed criteria in Attachment B. As
noted with this posting, the criteria were posted for public comment and will be included with the next posting of this standard.
The SDT reverted the voltage threshold in section 4.1.2 to the original text because commenters suggested that only facilities below 100 kV that
are on the Regional Entity’s list should be subjected to the criteria in Attachment B, while all facilities between 100 kV and 200 kV should be
subject to the criteria in Attachment B.
The SDT added a new 4.1.3 “Transmission lines operated below 100 kV that Regional Entities have identified as critical facilities for the purposes
of the Compliance Registry and are also determined by the Planning Coordinator as required to comply with this standard. "
The SDT renumbered old 4.1.3 to 4.1.4.
The SDT renumbered old 4.1.4 to 4.1.5 and reverted the voltage threshold to the original text consistent with the modification to section 4.1.2.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
The SDT added "4.1.6 Transformers with low voltage terminals connected below 100 kV that Regional Entities have identified as critical facilities
for the purposes of the Compliance Registry and are also determined by the Planning Coordinator as required to comply with this standard."
In response to comments that Requirement R5 is confusing the SDT deleted “to prevent cascading when protective relay settings limit
transmission loadability” from Requirement R5. Removing this term does not change the intent of the requirement.
Commenters indicated that the modifications to the applicability section may have the unintended consequence of increasing the burden on
Distribution Providers (DPs) with no reliability benefit; however, 1) the proposed modifications are directed changes and 2) the DPs would only be
affected if the Planning Coordinators apply the criteria in Attachment B and determine that the DPs have a facility that must comply with the
standard.
One comment indicated that Requirement R1’s VRF “High” has no justification. The SDT thinks that the revision to Requirement R1 to include
below 200 kV facilities should have no impact on the VRF assignment. If a facility is designated as a facility critical to the reliability of the BES the
impact on reliability is High regardless of the voltage level.
Some commenters noted the Reliability Coordinator (RC) is included in the SAR, but the SDT did not include the RC in the applicability section of
the standard. The SDT notes that the SAR contains a list of entities that could potentially be included in the standard, but it is not necessary that
the SDT include each entity in the applicability section of the standard.

Organization

Yes or No

Question 1 Comment

Northeast Power Coordinating
Council

IRC Standards Review
Committee

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 1 Comment
clear they allow in this Order and many others. Some immediate concerns with the proposal include: 1) It is
not clear what a “critical facilities list identified by the Regional Entity” is as specified within the order so
addressing the directive is a challenge. This standard is not the appropriate venue for development or
consideration of a critical facilities list. There is a supplemental SAR in process for the Reliability
Coordination project that is to address that topic. 2) Our understanding is that the application of NERC
standards is limited to the BES. Thus, facilities below 100 kV must be included in the Regional Entity
definition of BES to be eligible. The requirements should reflect this. The way the proposed standard reads,
one might conclude the PC must test every facility below 100 kV. This surely can’t be the intent.3)
Furthermore, the directive appears to require some action on the Regional Entities. From paragraph 60, “We
also direct that additions to the Regional Entities’ critical facility list be tested for their applicability to PRC-0231 and made subject to the Reliability Standard as appropriate.” It is not clear how this directive is reflected in
the standard to ensure that this work is completed prior to the PC’s performing their assessment for below
200 kV facilities. This standard is not the appropriate venue to determine or revise a critical facilities list, nor
is it appropriate for a Regional Entity to establish such a list. The bottom line is that the changes here are
significant enough that they would benefit from a group of experts reviewing the directives and proposing the
precise language that is needed.

MRO's NERC Standards Review
Subcommittee

However, this response is conditional depending on whether the criteria that will be established within
Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV.

Dominion Electric Market Policy

It depends on what Attachment B (R5.1) requires once it is developed. Without knowledge of the final content
developed for Attachment B, we do not support this.

E.ON U.S. LLC

E.ON U.S. believes that it is confusing the way R5 is currently written due to the last part of the sentence “ ...
when protective relay settings limit transmission loadability.” There is a need for clarification on how this is to
be applied. As an alternative: If the directive is to have the Planning Coordinator determine which sub-100kV
facilities should be subject to the Reliability Standard; R5 should be modified to read “Each Planning
Coordinator shall apply the criteria in Attachment B to determine which of the facilities in its Planning
Coordinator Area are to be included in 4.1.2 and 4.1.4.”

Transmission Access Policy
Study Group

The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make
all DPs potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the
standard is applicable to them. Because PRC-023 should never be applicable to a DP in its capacity as a DP
(as opposed to a TO that also happens to be registered as a DP), as explained in TAPS’ response to question
6 below, the SDT should simply remove DPs from the Applicability section to prevent the significant potential

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 1 Comment
for confusion and unnecessary costs.

Arizona Public Service Company

Agree with the content. However, there is no justification for VRF to be High for the circuits lower than 200 kV.

Kansas City Power & Light

Agree the changes for 4.1.2 and 4.1.4 are effective in meeting the “add in” approach in the FERC order.
However, do not agree with the approach in R5. R5 proposes to establish the criteria by which Reliability
Coordinators will determine facilities critical to the reliability of the BES. There are a variety of differing, and
often complex, operating conditions that dictate the need for transmission facilities. The TPL standards
require extensive studies of the transmission system be performed under steady state and dynamic
conditions to understand and identify sensitive areas of the transmission system and enable Reliability
Coordinators to identify flowgates in their respective regions. In light of the Reliability Coordinators
awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to the
Reliability Coordinators additional criteria.

Utility Services

The modifications to the Applicability Section meet the FERC directive but have the unacceptable unintended
consequence of increasing the burden on DPs with no reliability benefit. Specifically, the modifications make
all DPs potentially subject to PRC-023, thus requiring all DPs to incur costs to determine whether the
standard is applicable to them. Because PRC-023 should never be applicable to a DP in its capacity as a DP
(as opposed to a TO that also happens to be registered as a DP), as explained in our response to question 6
below, the SDT should simply remove DPs from the Applicability section to prevent the significant potential for
confusion and unnecessary costs.

ISO New England Inc.

We believe this directive needs to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directive. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
clear they allow in this Order and many others. Some immediate concerns with the proposal include: 1) Our
understanding is that the application of NERC standards is limited to the BES. Thus, facilities below 100 kV
must be included in the Regional Entity definition of BES to be eligible. The requirements should reflect this.
The way the proposed standard reads, one might conclude the PC must test every facility below 100 kV. This
surely can’t be the intent.2) Furthermore, the directive appears to require some action on the Regional
Entities. From paragraph 60, “We also direct that additions to the Regional Entities’ critical facility list be
tested for their applicability to PRC-023-1 and made subject to the Reliability Standard as appropriate.” It is
not clear how this directive is reflected in the standard to ensure that this work is completed prior to the PC’s
performing their assessment for below 200 kV facilities. The bottom line is that the changes here are
significant enough that they would benefit from a group of experts reviewing the directives and proposing the
precise language that is needed.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 1 Comment

Long Island Power Authority

There appears to be a disconnect between FERC’s “sub 100 kV” and proposed “below 200 kV” revision in the
Applicability Section. LIPA seeks clarification on this. Also, by whom and by which method will the criticality of
the substations be ascertained?

Ameren

Attachment B as mentioned in R5 is not available for review.

American Electric Power

AEP understands the intent of the FERC Order (Paragraph 60) to address the sub-100 KV facilities only if
they are associated with critical facilities above 100 KV. The applicability and the associated requirements
should be reworded to ensure that the Planning Coordinator does not have to identify critical facilities below
100 KV.

Southern California Edison

Applicability clause 4.12 and 4.14 - Formulating a consistent methodology test to determine for a sub 200KV
facility by the Planning Coordinator is quite an uphill task keeping in view the different circuit configuration
different utilities may have. It is best left alone to each utility to determine the facilities which can be a
candidate for inclusion as a bulk power system. The current risk based assessment criteria to determine bulk
power facility should be continued.

American Transmission
Company

Yes

However, this affirmative response is conditional depending on whether the criteria that will be established
within Attachment B (see R5.1) are reasonable and apply to properly qualified facilities below 200 kV.

Pepco Holdings, Inc - Affiliates

Yes

While philosophically we do not agree that this standard should apply to facilities below 100kV (i.e. facilities
that are not defined as BES facilities) we believe that as long as a sound engineering methodology is
developed and applied uniformly to identify those facilities critical to the reliability of the BES, then the revised
wording is acceptable. Our response, however, is qualified based on being granted an opportunity to
comment and vote on the methodology once it is developed.

NPPD

Yes

As long as you keep BES.

Independent Electricity System
Operator

Yes

We agree with the Applicability Section and the modification to R5. Note that there is a discrepancy between
the entities listed in the Applicability Section and those checked off in the SAR. The latter indicates that the
SAR is also applicable to the RC, which we do not believe is required.

Bonneville Power Administration

Yes

FirstEnergy

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

PacifiCorp

Yes

Southern Company

Yes

TSGT System Planning Group

Yes

NV Energy

Yes

Consumers Energy

Yes

Idaho Power - System Protection

Yes

ComEd

Yes

Manitoba Hydro

Yes

ITC Holdings

Yes

Question 1 Comment

Yes
Xcel Energy

Yes

Duke Energy

Yes

Wisconsin Electric

November 1, 2010

No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13

R1 h a s b e e n m o d ifie d to a d d re s s th e d ire c tive in P a ra g ra p h 244 o f Ord e r n o . 733. Do yo u a g re e th a t th is is a n a c c e p ta b le a n d
e ffe c tive m e th o d o f m e e tin g th is d ire c tive ? If n o t, p le a s e e xp la in .

Summary Consideration:
Commenters indicated for a variety of reasons that the requirement related to out-of-step blocking added to Requirement R1 is confusing. The
SDT agrees and removed out-of-step blocking from Requirement R1. The requirement pertaining to evaluation of out-of-step blocking protection
has been moved to a separate requirement (now Requirement R2) to more clearly delineate this requirement from assessment of relay loadability
of phase protective relays.
One commenter noted that it is not clear how loadability requirements apply during fault conditions. In the new requirement the SDT clarified that
the evaluation must ensure that out-of-step blocking elements allow tripping of phase protective relays for faults that occur during the loading
conditions used to verify transmission line relay loadability per Requirement R1.
Some commenters indicated that the word “settings” should be replaced throughout R1 when referring to a part, or sub-requirement of R1. The
SDT modified Requirement R1 by replacing the word “settings” with “criteria.” This is consistent with the main Requirement R1 which in the
presently approved standard (PRC-023-1) refers to sub-requirements R1.1 through R1.13 as criteria to prevent phase protective relay settings
from limiting transmission system loadability.
Some commenters identified an error in the draft standard in criterion 9 in Requirement R1 that resulted in omitting a phrase contained in the
presently approved standard. The SDT modified criterion 9 in Requirement R1 to reinsert the deleted phrase.
One commenter noted that this directive needs to be addressed by a full standard drafting team to adequately address this directive and identify
equally effective alternatives to the Commission’s directives. The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been
reconvened to address the directed modifications to the standard. The SDT believes that the issues indentified in Order No. 733 can be
addressed adequately by this SDT with industry stakeholder input through the NERC Standard Development Process.
One commenter indicated that they agreed with the inclusion of Section 2 of Attachment A in the Requirement Section but the proposed
modification may not fully meet the directive that the additional requirement is assigned a VRF and VSL. This may require the creation of a
separate main requirement rather than simply including the condition as a part of a requirement. However, the VRFs and VSLs are associated
directly with R1, and thus all its’ subparts/criteria. Therefore, as Attachment A is referenced as being part of R1, the R1 VRFs and VSLs
automatically apply.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 2 Comment
1. The last sentence in R1 should be revised to read: Each Transmission Owner, Generator Owner, and
Distribution provider shall evaluate relay loadability at 0.85 per unit voltage, and a power factor angle of
30 degrees.
2. Settings are to be applied as listed following:”Setting” should be replaced throughout R1 when referring to

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 2 Comment
a part, or sub-requirement of R1. The terminology should be whatever is preferred by
NERC.Requirement R1, Parts 7, 8 and 9:
3. Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration” with "under any
system condition:" 7. Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current flow from the load
to the generation source under any system condition.8. Set transmission line relays applied on the bulk
system-end of transmission lines that serve load remote to the system so they do not operate at or below
115% of the maximum current flow from the system to the load under any system condition.9. Set
transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk
system so they do not operate at or below 115% of the maximum current flow from the [___] to the under
any system condition. [Brackets added, also see further comment on missing wording following]This
phrase "under any system configuration" could be construed as being too all-inclusive, as one could
postulate multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in
a direction for which the system was not originally designed. As with the second comment below, the
phrase "under any system condition" was part of Revision 1 and is unchanged by Revision 2, however,
the new applicability to below 200 kV creates the new concern.
4. Requirement 1, part 9:As currently written, Requirement 1, part 9 states:9. Set transmission line relays
applied on the load-end of transmission lines that serve load remote to the bulk system so they do not
operate at or below 115% of the maximum current flow from the [___] to the under any system
configuration. [Brackets added]Some words are missing. The brackets have been added above to show
one place where at least some of the needed wording may be missing. A rewrite is necessary in order for
this sentence to make any sense.

Pepco Holdings, Inc - Affiliates

The revised wording in paragraph R1 regarding out-of-step blocking schemes is confusing. We suggest
rewording the paragraph by splitting the sentence as follows: ...while maintaining reliable protection of the
BES for all fault conditions. Use of out-of-step blocking schemes shall be evaluated to ensure that they do
not block tripping for faults during the loading conditions defined within these requirements.

Bonneville Power Administration

The modified Requirement R1 requires that one of the 13 criteria be used to prevent out-of-step blocking
schemes from blocking tripping for fault conditions. The problem is that the 13 criteria are only related to
loading conditions, and it is not clear how they would be applied to prevent out-of-step blocking schemes from
blocking a trip during a fault, or if it is even possible to use these criteria for this purpose. The modified
Requirement R1 requires actions that are ambiguous and we cannot support it as written.

IRC Standards Review

We believe this directive needs to be addressed by a standards drafting team to ensure the precise language
is crafted to adequately address the directive. Furthermore, we believe only the full standards drafting team

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Committee

Question 2 Comment
could identify equally effective alternatives to the Commission’s directives as they have made clear they allow
in this Order and many others.

E.ON U.S. LLC

Since correct operation of the out-of-step blocking feature is integral to and only a single component of a
successful trip operation (for fault conditions), this is already included in the requirement to “maintain reliable
protection of the BES for all fault conditions” and does not have to be mentioned separately. Also, R1 (as
written) may be interpreted to require one of the settings (1 through 13) to be used to prevent out-of-step
blocking schemes from blocking tripping for fault conditions. But Settings 1 thru 13 do not address specific
setting criteria for out-of-step blocking.

TSGT System Planning Group

We suggest that the added phrase be removed from R1 and a new requirement created. Suggested wording
is “Protection Systems that block for stable swings or out-of-step conditions shall be evaluated to ensure that
appropriate tripping will occur for in-section faults that occur during the condition. Some additional delay may
be required and is acceptable to ensure that the appropriate tripping occurs.”

NV Energy

The proposed phrase added to R1 is only a start: “. . . , and to prevent its out-of-step blocking schemes
from blocking tripping for fault conditions.” The specific wording proposed by the Drafting Team may
prevent using the out-of-step-block functions of many modern and widely used line protection relays (e.g.
SEL-321 and later models and GE-UR). These relay’s OSB function first blocks the protection elements from
tripping, then uses a short delay and/or other information to determine whether the observed and perhaps
evolving condition really represents a fault, in which case the blocking is reset to allow tripping. Such a
block/reset operation is the most common technology available and would appear to lie within the intent of
FERC in paragraph 244, but could be excluded by the presently proposed language. If an out-of-step
blocking phrase is inserted in Requirement R1 of the standard, the emphasis should be modified to read
something like: “. . . , and its out-of-step blocking schemes must allow tripping for fault conditions.”
This
standard should also require that out-of-step blocking settings coordinate with both the loadability and
protection characteristics.
The out-of-step blocking references would seem to fit best within the
organization of the standard if included as a new Requirement R2 (FERC’s paragraph 244 anticipates “. . . an
additional Requirement . . .”), with re-numbering of the proposed R2 through R5 as R3 through R6. The
essential content of the DT’s proposed phrase in R1 would be included as part of this new R2, which would
read something like:R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall
evaluate its out-of-step blocking schemes to ensure that both: R2.1. Out-of-step blocking schemes allow
tripping for fault conditions during the loading conditions determined from Requirement R1 parts R1.1 through
R1.13. R2.2. Relay out-of-step blocking settings coordinate with both the relay loadability characteristic
determined from Requirement R1 parts R1.1 through R1.13 and the facility protection settings. The Measure
for this proposed R2 would read something like:M2.The Transmission Owner, Generator Owner, and
Distribution Provider with out-of-step blocking schemes shall have evidence such as spreadsheets or

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 2 Comment
summaries of calculations to show that each of its out-of-step blocking schemes is set to comply with the
requirements of R2.1 and R2.2. The VSL for R1 would not change; specifically it would not reference out-ofstep blocking schemes. The VSL for this proposed new R2 would be “Severe” and read something like:A
Transmission Owner, Generator Owner, or Distribution Provider did not allow its out-of-step blocking schemes
to trip for fault conditions during the loading conditions determined from Requirement R1 parts R1.1 through
R1.13. ORA Transmission Owner, Generator Owner, or Distribution Provider did not coordinate operation of
its out-of-step blocking schemes with both the relay loadability characteristic determined from Requirement
R1 parts R1.1 through R1.13 and the facility protection settings.

Independent Electricity System
Operator

We agree with the inclusion of Section 2 of Attachment A in the Requirement Section but the proposed
modification may not fully meet the directive that the additional requirement is assigned a VRF and VSL. This
may require the creation of a separate main requirement rather than simply including the condition as a part
of a requirement.

Southern California Edison

Requirement R1.7, R1.8, R1.13 do not provide a clear guideline on generators connected to the load center
on Radial basis, where load current into the generators ( forward direction current seen by the relay) is just an
auxiliary load and insignificant compared to the transmission line rating.

ISO New England Inc.

Requirement R1, Parts 7, 8 and 9:Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system
configuration” with "under any system condition:" 7. Set transmission line relays applied at the load center
terminal, remote from generation stations, so they do not operate at or below 115% of the maximum current
flow from the load to the generation source under any systemcondition.8. Set transmission line relays applied
on the bulk system-end of transmission lines that serve load remote to the system so they do not operate at
or below 115% of the maximum current flow from the system to the load under any systemcondition.9. Set
transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk
system so they do not operate at or below 115% of the maximum current flow from the [___] to the under any
system condition. [Brackets added, also see further comment on missing wording following]This phrase
"under any system configuration" could be construed as being too all-inclusive, as one could postulate
multiple events, e.g., simultaneous outages, which however unlikely could permit power flows in a direction
for which the system was not originally designed. As with the second comment below, the phrase "under any
system condition" was part of Revision 1 and is unchanged by Revision 2, however, the new applicability to
below 200 kV creates the new concern.Requirement 1, part 9:As currently written, Requirement 1, part 9
states:9. Set transmission line relays applied on the load-end of transmission lines that serve load remote to
the bulk system so they do not operate at or below 115% of the maximum current flow from the [___] to the
under any system configuration. [Brackets added]
Some words are missing. The brackets have been
added above to show one place where at least some of the needed wording may be missing. A rewrite is

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 2 Comment
necessary in order for this sentence to make any sense.

Long Island Power Authority

Requirement R1, Parts 7, 8 and 9, replace the phrase “under any system configuration” with "under any
system condition:" This phrase "under any system configuration" could be construed as being too allinclusive, as one could postulate multiple events, e.g., simultaneous outages, which however unlikely could
permit power flows in a direction for which the system was not originally designed. Requirement 1, part 9:As
currently written, Requirement 1, part 9 states:9. Set transmission line relays applied on the load-end of
transmission lines that serve load remote to the bulk system so they do not operate at or below 115% of the
maximum current flow from the [___] to the under any system configuration. [Brackets added]
Some words
are missing. The brackets have been added above to show one place where at least some of the needed
wording may be missing. A rewrite is necessary in order for this sentence to make any sense.

ITC Holdings

The proposed wording seems out of place in this requirement and is not clear as how it is being applied to
subrequirements 1 - 13

NPPD

Yes

I'm ok with that. It could have easily been left in Attachment A. You didn't bring the other language from
attachment A to R1. You could of created a separate requirement for OOS, but I'm fine with moving it to R1.

FirstEnergy

Yes

MRO's NERC Standards Review
Subcommittee

Yes

Dominion Electric Market Policy

Yes

Arizona Public Service Company

Yes

American Transmission
Company

Yes

Southern Company

Yes

Consumers Energy

Yes

Idaho Power - System Protection

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Kansas City Power & Light

Yes

ComEd

Yes

Manitoba Hydro

Yes

Ameren

Yes

American Electric Power

Yes

Question 2 Comment

Yes
Xcel Energy

Yes

Duke Energy

Yes

Wisconsin Electric

November 1, 2010

No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
3.

Summary Consideration:
Many commenters were concerned about the coordination with the relay loadability requirements of R1 – criterion 1.10 with the transformer
damage curve as expressed in IEEE C37.91 Figure A4, which defines transformer through-fault withstand capability as starting at twice the
nominal nameplate rating; R1, criterion 1.10 requires that loadability be 150% of the maximum nameplate (which itself is often 1.66 times the
nominal nameplate – resulting in loadability of over 2.5 times the nominal nameplate rating).

IEEE C37.91 Figure A5 has two components to the thermal damage curve for through-faults: the “thermal component” begins at 2x the
transformer nominal nameplate rating, and seems to be the root of commenters’ concerns. The “mechanical component” begins at a current equal
to the reciprocal of the twice the transformer impedance. The commenters are correct in their characterization of the “thermal component” of the
transformer damage curve, in that it is not possible to satisfy the posted PRC-023-2 R1, criterion 10 and also protect the transformer for currents in
this region. Upon careful consideration of FERC Order 733, the SDT revised R1 criterion 10 to reference only the mechanical withstand capability.
Many commenters questioned the inclusion of “limiting piece of equipment” rather than “transformer”, as the fault withstand capability of terminal
equipment (switches, breakers, current transformers, etc) may be unavailable. Upon further consideration of FERC Order 733, the SDT modified
criterion 10 by replacing “limiting equipment” with “transformer.”

Organization

Yes or No

Question 3 Comment

Pepco Holdings, Inc - Affiliates

Bonneville Power Administration

In some cases, Section 10 of Requirement R1 would be impossible to meet. For example, a 150/200/250
MVA, OA/FOA1/FOA2 transformer is required by Section 10 to have its protection set so that it doesn’t
operate at or below 150% of the maximum transformer rating of 250MVA, or 1.5x250=375MVA. The modified
Section 10 would also require that the protection not expose the transformer to a fault level and duration that

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 3 Comment
exceeds its capability. According to IEEE C37.91, a through-fault of two times the transformers base rating,
2x150=300MVA, will be damaging to the transformer. For this particular transformer, which is not unusual,
Requirement R1, Section 10, requires the protection to operate for through faults of 300MVA or greater, but
not operate for loads of 375MVA or less. It is impossible to simultaneously meet both of these conditions, so
Section 10 is unacceptable. One possible way to correct the problem is to change the requirement so that the
protection does not operate below 200% of the transformer base rating. This would allow the protection to
meet IEEE C37.91 for through-faults and still allow overloading of the transformer.

FirstEnergy

Although it is true that the FERC directive specifically states "limiting piece of equipment" their reasons and
justifications all involve transformers. We propose replacing "limiting piece of equipment" with "transformer"
would meet the FERC's reliability concern as well as provide clarity to applicable entities. We believe this is
an equally effective means of meeting the directive.

IRC Standards Review
Committee

MRO's NERC Standards Review
Subcommittee

The word change meets the strict interpretation of the directive, but it is not necessarily improving the
reliability of the system. Faults are cleared in cycles and transformer damage curves do not start until at least
one second

Dominion Electric Market Policy

The requirement is not clear. For example, how do we determine and verify the limiting piece of equipment
under fault conditions? It might be a splice or a jumper. Since the document refers to duration, this seems to
apply mainly to transformer overcurrent relaying which would be for overload protection not fault protection
that has no intentional delay.

E.ON U.S. LLC

E.ON U.S. is concerned that the proposal requires a fault protection scheme separate from the phase
overload relays. With the phase overload relays set at 150% of the maximum transformer nameplate, they (by
themselves) will not be able to coordinate with the transformer damage curve (as defined by IEEE) for low
level faults.R1, Section 10 meets the directive of Paragraph 203; however it is not clear that Section 10 only
applies when there is no high side breaker at the transformer, as discussed in Order No. 733. E.ON U.S.
recommends that an exclusion of the transmission line relay settings should be considered when transformer
overload protection is provided by other means (i.e. A low side breaker trip or a direct transfer trip of the
remote breaker initiated by an overload relay installed on the transformer).

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 3 Comment

NPPD

Setting the relay to 150% of a 336MVA or 500MVA transformer can force you to cross the transformer
damage curve and now your transformer is at risk to loss of life.

Idaho Power - System Protection

The reworded Requirement should to be clarified. The fault level and duration that the limiting element will be
exposed can be a function of fault location and contingencies, such as relay failures, that are not addressed
or defined. No measure is specified in the reliability standard that will demonstrate compliance with the
revised requirements in R1.10.

Kansas City Power & Light

Although setting #10 includes language to protect the most limiting element for a transmission circuit ending
with a transformer, the relay settings in the bulleted items are absent any consideration for other elements
such as disconnect switches, wave traps, current transformers, potential transformers, etc. and are only with
concern to the transformer. The relay settings should consider the fault current capabilities of all the facilities
involved and be set in magnitude and duration of the lowest facility rating.

Ameren

The language is not clear. It appears that the transmission line relays are being used as the thermal overload
protection for the transformer.

ITC Holdings

R1 -10 is all about loadability of the relays protecting the transformer. If the requirements of R1-10 cannot be
met without exceeding the transformer damage curve, then we go to R1-11. We do not feel that there should
be anything to do with fault duty.

Duke Energy

R1.10 has added the requirement that protection settings can’t expose transformers to fault levels and
durations that exceeds its capability, while at the same time not operate at or below 115% of highest
emergency rating. We would argue that an overcurrent relay cannot be set to satisfy both requirements. A
transformer’s through-fault protection curve (C37.91) begins at 200% of the transformers self-cooled rating.
The highest emergency rating is commonly 150% (or higher) of the transformer’s highest (cooled) rating.
Overcurrent relays could not be set to coordinate with both the damage curve and the overload rating.

South Carolina Electric and Gas

This requirement needs to be refined to clearly state the intent. It is unclear if “limiting piece of equipment” is
referring to just transformers or other elements. Some of the elements involved in the construction of a
transmission line/transformer arrangement such as line conductors, etc. may not have published fault current
ratings. It is unclear how to determine the most limiting piece of equipment if published fault current ratings
are not available for these devices

American Transmission

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Company

Question 3 Comment
one second.

Arizona Public Service Company

Yes

Northeast Power Coordinating
Council

Yes

PacifiCorp

Yes

Southern Company

Yes

TSGT System Planning Group

Yes

NV Energy

Yes

Consumers Energy

Yes

ComEd

Yes

Manitoba Hydro

Yes

ISO New England Inc.

Yes

Long Island Power Authority

Yes

American Electric Power

Yes
Yes

Xcel Energy
Wisconsin Electric

November 1, 2010

Yes
No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
4.

Summary Consideration:
The SDT modified the wording of R4 as follows. "Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to utilize
Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability shall provide....” as a result of comments.
The SDT agreed to remove the Regional Entity from the list of entities receiving this information in Requirement R4.
Comments indicated that all relay setting limitations should be included in the Facility Rating per FAC-008. The operator will then be made aware
of any and all relay limitations through the use of those ratings (FAC-009). FERC Order 733 paragraph 186 requires an additional notification of
relay setting limitations specifically for relay settings that are set based upon the 15 minute criteria. This is being done to ensure that transmission
operators have knowledge of which facilities have relays set using a 15 minute criteria and which facilities have relays set using a 4-hour criteria.
The SDT believes that requiring periodic submittals of this information will help create a clear and less ambiguous requirement and improve
measurability which should aid applicable entities in compliance and result in more uniform enforcement actions.

Organization

Yes or No

Question 4 Comment

Bonneville Power Administration

This change adds an additional burden to the applicable entities, but serves no purpose other than to satisfy
FERC’s misinterpretation of what a fifteen-minute facility rating is.

ERCOT ISO

The entities who receive the list of facilities should be the same from R3 to R4.

Northeast Power Coordinating
Council

Referring to the response to Question 2 above, “Setting” should be replaced with Part, or Sub-requirement,
whichever is the terminology preferred by NERC to use.

Pepco Holdings, Inc - Affiliates

To avoid confusion, the wording of R3 should be revised as follows: “Each Transmission Owner, Generator
Owner, and Distribution Provider that chooses to utilize Requirement R1 Setting 2 as the basis for verifying
transmission line relay loadability shall provide....” The problem with the SDT’s proposed wording of R3 is
that suppose a TO chose to utilize R1 Setting 1 criteria (> 150% of 4 hr rating) as their basis for verifying
loadability, but the actual relay setting also satisfied criteria R1 Setting 2 (> 115% of 15 min rating) the entity
may interpret that they are still obligated to forward the list since the relay settings also satisfied R1 Setting 2
criteria

FirstEnergy

We suggest removing the Regional Entity from the list of entities receiving this information since they do not
have a reliability-related need for it.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 4 Comment

IRC Standards Review
Committee

We do not understand the need for this directive or requirement. A relay that is set to operate at 115%
greater than the 15-minute rating of the facility does not equate to damage occurring on that facility if
operated at that point in 15 minutes. Furthermore, it does not mean the relay will operate in 15 minutes nor
does it mean the operator has only 15 minutes to take action. In fact, the operator may have less time
depending on the time delay set on the relay. It is no different than any other relay. Usually, the facility will
be operated with some buffer so that there is no chance that an entity could trip the facility due to loading
above the relay limit. In fact, the transmission operator should be aware of any relay that might be the limiting
facility so they can operate the facility with some margin of error to ensure they don’t inadvertently cause a
relay operation due to loading.

TSGT System Planning Group

We think that the data needs to be given only to the Transmission Operators, which is what FERC Order No.
733 requires. We also believe that an initial submittal is sufficient until any responsible entity begins or stops
using Requirement 1, Setting 2 for setting a phase protective relay that is used to protect an applicable
facility. There is no need for periodic duplicate submittals.

Kansas City Power & Light

Do not agree that the Regional Entity be included as a recipient of the list of transmission facilities. By NERC
definition, the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability
Standards and is not an operating entity. It is inappropriate to include Regional Entities as an entity to provide
this information outside of the audit process established by the NERC Rules of Procedure. By definition, in
the NERC Reliability Terminology, the Regional Entity is a compliance enforcement agent and not an
operating organization of the Bulk Power System, and, therefore, has no operating reason to obtain this
information. See definition below:Regional Entity - The term ‘regional entity’ is defined in Section 215 of the
Federal Power Act means an entity having enforcement authority pursuant to subsection (e)(4) [of Section
215]. A regional entity (RE) is an entity to which NERC has delegated enforcement authority through an
agreement approved by FERC. There are eight RE’s. The regional entities were formed by the eight North
American regional reliability organizations to receive delegated authority and to carry out compliance
monitoring and enforcement activities. The regional entities monitor compliance with the standards and
impose enforcement actions when violations are identified.

Independent Electricity System
Operator

The proposed revision goes beyond what’s asked for in the directive as it requires the responsible entities to
provide the list to entities other than the TOP. The directive asks for providing the list to the TOP only.

Southern California Edison

The relay if set according to Requirement R1.2 are based upon 15 minute highest seasonal facility loading
duration. This gives sufficient time for the operators to take manual corrective action, if the deem so. There is
no need for the Registered entity to provide a list, as it would not be efficient and cost effective.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 4 Comment

ISO New England Inc.

MRO's NERC Standards Review
Subcommittee

Yes

Dominion Electric Market Policy

Yes

E.ON U.S. LLC

Yes

Arizona Public Service Company

Yes

American Transmission
Company

Yes

PacifiCorp

Yes

Southern Company

Yes

NV Energy

Yes

NPPD

Yes

Consumers Energy

Yes

Idaho Power - System Protection

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

ComEd

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

Ameren

Yes

American Electric Power

Yes

ITC Holdings

Yes

Question 4 Comment

Yes
Xcel Energy

Yes

Duke Energy

Yes

Wisconsin Electric

November 1, 2010

No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
5.

Summary Consideration:

The FERC Order “direct(s) the ERO to document, subject to audit by the Commission, and to make available for review to users,
owners and operators of the Bulk-Power System, by request, a list of those facilities that have protective relays set pursuant subrequirement R1.12.”
Since the data is subject to audit, the SDT interprets this to mean that the ERO must gather and have continuously available a list of
facilities using Requirement R1 criterion 12. The SDT therefore interprets the “by request” nature of the directive to indicate the way
the ERO makes the list available to users, owners and operators of the Bulk-Power System, not how the ERO gathers the data from
TOs, GOs and DOs.
As suggested by one of the comments, the SDT intended for registered entities to provide this data to their Regional Entities who
would in turn provide it to the ERO. Although some comments have suggested other ways to accomplish this, the majority of
responders appear to agree with the SDT proposed method.

Organization

Yes or No

ERCOT ISO

Question 5 Comment
The entities who receive the list of facilities should be the same from R3 to R4.

Northeast Power Coordinating
Council

R4 addresses the directive, but as commented on previously, “Setting” should be replaced with Part, or Subrequirement, whichever is the terminology preferred by NERC to use.

IRC Standards Review
Committee

The objective of R4 as written is unclear and does not conform with the results-based concept in that it does
not clearly specify a reliability directive. We suggest removing this requirement altogether as we do not
believe this should be an on-going enforceable requirement. Rather, we think it makes more sense for NERC
to use section 1600 of its Rules of Procedure to request the data. We believe that NERC and the
Commission will likely determine that they don’t need to continually receive this data after reviewing it the first
time. Nothing in the directive indicates this must be accomplished through a standard. If NERC and FERC
do identify a continuing need for the data, the standard could be modified at a later date.

MRO's NERC Standards Review
Subcommittee

While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 5 Comment

Arizona Public Service Company

FERC Order required the list to be made available for review to users, owners and operators of the BulkPower System upon request. Requirement 4 does not include the "request" requirement, implying that the
Registered Entity must provide the list without a request. Further, the requirement does not specify what the
Regional Entity will do with the list once it is provided.

TSGT System Planning Group

FERC Order No. 733 requires the settings be provided upon request and no initial or periodic submittal is
required.

Kansas City Power & Light

The proposed R4 exceeds the concerns of FERC in this matter. FERC directed a requirement to provide
information upon request. The proposed R4 requires data submission without request of the parties with
interest to the information. Recommend the SDT consider modifying this requirement to provide this
information upon the request of appropriate operating parties.Do not agree that the Regional Entity be
included as a recipient of the list of transmission facilities. By NERC definition, the Regional Entity is the
Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is not an operating
entity. It is inappropriate to include Regional Entities as an entity to provide this information outside of the
audit process established by the NERC Rules of Procedure. By definition, in the NERC Reliability
Terminology, the Regional Entity is a compliance enforcement agent and not an operating organization of the
Bulk Power System, and, therefore, has no operating reason to obtain this information. See definition
below:Regional Entity - The term ‘regional entity’ is defined in Section 215 of the Federal Power Act means an
entity having enforcement authority pursuant to subsection (e)(4) [of Section 215]. A regional entity (RE) is an
entity to which NERC has delegated enforcement authority through an agreement approved by FERC. There
are eight RE’s. The regional entities were formed by the eight North American regional reliability organizations
to receive delegated authority and to carry out compliance monitoring and enforcement activities. The
regional entities monitor compliance with the standards and impose enforcement actions when violations are
identified.

Independent Electricity System
Operator

The objective of R4 as written is unclear. We speculate that by requiring the TOs, GOs and DPs to provide
the list (associated with R1, Section 12) to the REs, the ERO will collect the relevant information from all REs
to facilitate provision of such information to owners, users and operators of the BES upon request. If this is
the intent, we suggest to replace “REs” with “ERO” to make it a more direct and efficient way to provide the
information needed to support the request for information process.The requirement as written does not
conform with the results-based concept in that it does not clearly specify a reliability directive. Hence
alternatively, we suggest removal of this requirement altogether since the directive asks the ERO to
document, subject to audit by the Commission, and to make available for review to users, owners and
operators of the Bulk-Power System, by request, a list of those facilities. This can be dealt with outside of the
standard process, for example, through RoP 1600.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 5 Comment

Long Island Power Authority

FERC order 733 p224 requires that the list of facilities that have protective relays set pursuant to R1.12 of
anticipated overload be made available to users, owners, and operators of the BPS. However, the proposed
revision to R4 requires the list to be made available to Regional Entity only. Please clarify. Also, FERC order
uses the term “by request” which is missing from the proposed revision.

American Transmission
Company

Yes

While achievable, this will not come without effort and does not necessarily improve the reliability of the BES
commensurate with the compliance burden.

Pepco Holdings, Inc - Affiliates

Yes

FirstEnergy

Yes

Dominion Electric Market Policy

Yes

E.ON U.S. LLC

Yes

PacifiCorp

Yes

Southern Company

Yes

NV Energy

Yes

NPPD

Yes

Consumers Energy

Yes

Idaho Power - System Protection

Yes

ComEd

Yes

Manitoba Hydro

Yes

ISO New England Inc.

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

American Electric Power

Yes

ITC Holdings

Yes

Question 5 Comment

Yes
Xcel Energy

Yes

Duke Energy

Yes

Wisconsin Electric

November 1, 2010

Paragraph 224 addresses R1.12, requiring documentation and making available a list of facilities that have
protective relays set pursuant to R1.12. Although Order 733 was silent on R1.13, should the new R4 not also
apply to R1.13?
No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
6.

Requirement R5 and part 5.1 (previously Requirement R3 and part 3.1) have been modified to establish the framework to address
the directive in Paragraph 69 of Order no. 733, although the criteria itself (which will be Attachment B) is still being developed. Do
you agree that this is an acceptable and effective method of meeting this directive considering that Requirement R5 is establishing
the construct to insert the criteria at a future time in the form of Attachment B? If not, please explain.

Summary Consideration:
A majority of commenters do not believe, or were unable to determine whether, the construct established in Requirement R5 is an acceptable and
effective method of meeting this directive. Almost all commenters, regardless of whether they responded “Yes” or “No,” indicated their responses
are conditional pending review of the criteria. The criteria that Planning Coordinators will use to determine which facilities must comply with PRC023 were posted on September 23 for a 20-day informal comment period. The SDT has reviewed Requirement R5 and the criteria in Attachment B
and has made conforming changes to ensure no conflicts exist. The full standard with Attachment B will be posted for a 45-day formal comment
period.
One commenter disagreed with the approach in Requirement R5, part R5.1, noting there are a variety of differing, and often complex, operating
conditions that dictate the need for transmission facilities. The commenter observed it is not necessary to dictate additional criteria because the
TPL standards already require extensive studies of the transmission system. The SDT believes the proposed criteria defining the test Planning
Coordinators will use to determine which facilities must comply with PRC-023 will address the commenters concerns. The proposed criteria are
consistent with the simulations and assessments required by the TPL Reliability Standards and allow the Planning Coordinators to utilize those
assessments as directed in Order No. 733.
One commenter noted that the SDT needs to work closely with the Reliability Coordination SDT (Project 2006-06) which is tasked with defining
critical facilities or indentifying criteria for developing a list of critical facilities. The commenter disagreed with use of the phrase “facilities that are
critical” in this requirement and cautioned that a requirement to create a list of critical facilities should not be addressed in this standard. The SDT
notes that although the phrase “critical to reliability of bulk electric system” appears in the approved PRC-023-1 and is used in Order No. 733, the
SDT recognizes that use of the same or similar terms in multiple standards will result in confusion. Use of the phrase “critical to reliability of the
Bulk Electric System” in PRC-023 is intended to have meaning specific to the issue of relay loadability; specifically to identify facilities, that if they
trip due to relay loadability following an initiating event, may contribute to undesirable system performance similar to what occurred during the
August 2003 blackout. The SDT has modified the standard to replace the phrase “critical to the reliability of the bulk electric system” with “that
must comply with this standard.” The SDT believes this will avoid potential confusion and that reliability will be adequately addressed because the
criteria in Attachment B identify all facilities that must be subject to this standard to maintain reliability of the Bulk Electric System.
Some commenters noted that Requirement R5, Part 5.3 should require that the Planning Coordinator provide its list of facilities to all Transmission
Owners, Generator Owners, and Distribution Providers within its area; not only the entities with facilities on the list. The SDT believes this is
consistent with the intent of the requirement and has modified the standard accordingly to make this requirement explicit.
One commenter noted that Requirement R5, Part 5.1 is unnecessary since the process to use the criteria in Attachment B would almost certainly
be to simply apply the criteria and that requiring documentation of such a process will result in increased paperwork and additional preparation for
an audit without a reliability benefit. The SDT agrees that this part of Requirement R5 is unnecessary and has removed it from the Standard.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Several commenters requested modifications that are outside the scope of the SAR for this project.
•

Two commenters indicated Requirement R5 should include wording that limits the scope of the transmission facilities to be evaluated to only
those that can be tripped by the relay settings subject to Requirement R1 and that the SDT should add a requirement that the Transmission
Owners, Generator Owners, and Distribution Providers provide the Planning Coordinators with a list of such transmission facilities. The SDT
believes that since the existing Requirement R3 does not restrict the facilities which the Planning Coordinator must consider, the proposed
modifications are outside the scope of the SAR for this project. The SDT further believes that transmission facilities that have no phase
protective relays subject to tripping on load are sufficiently uncommon that the proposed requirement would place a significant burden on
Transmission Owners, Generator Owners, and Distribution Providers while providing limited benefit to the Planning Coordinators.

•

Two commenters believe the standard should not be applicable to Distribution Providers. The SDT believes that since the approved PRC023-1 includes Distribution Providers, the proposal to exclude Distribution Providers is outside the scope of the SAR for this project. However,
the SDT further believes it is possible for a Distribution Provider to own a relay that protects a transmission facility, even if the Distribution
Provider does not own the protected facility.

•

One commenter observed there is much confusion about the registration of Planning Coordinators and suggests that while the Order proposes
the Planning Coordinator perform this test, it could be assigned to the Regional Entity or the Reliability Coordinator (as in the SPCTF
recommendation) and achieve the same result. The SDT notes the approved PRC-023-1 already assigns the Planning Coordinator with the
requirement to determine which facilities must comply with PRC-023. The SDT believes there is no reason to revisit this issue.

One commenter believes it is not appropriate to modify Requirement R5, part 5.3 to include the Regional Entity as a recipient of the list of
transmission facilities because the Regional Entity is the Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is
not an operating entity. The SDT believes the role of the Regional Entity in compliance enforcement does not preclude a Reliability Standard from
including Regional Entities as the recipients of data. The SDT further believes that providing the Regional Entity with the list of transmission
facilities subject to Requirement R1 is the most direct way to address the Commission’s objective to aid in the overall coordination of planning and
operational studies among Planning Coordinators, Transmission Owners, Generator Owners, Distribution Providers, and Regional Entities.
Two commenters believe the criteria in Attachment B along with any necessary modifications to the associated requirement should be developed
by a full drafting team. The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been reconvened to address the directed
modifications to the standard. The criteria that Planning Coordinators will use to determine which facilities must comply with PRC-023 were
developed with the assistance of a “Blue Ribbon Panel” comprised of members from each region who are Subject Matter Experts in the area of
Transmission Planning. Order No. 733 directs that the criteria in PRC-023 must include or be consistent with the system simulations and
assessments that are required by the TPL Reliability Standards, and input from the Blue Ribbon Panel provides additional expertise necessary to
develop the directed modifications.

Organization
Northeast Power Coordinating
Council

November 1, 2010

Yes or No

Question 6 Comment

Requirement R5 states that the Planning Coordinator will determine which facilities below 200kV are critical to
the reliability of the Bulk Electric System by applying criteria defined in Attachment B, which is to be
developed. Therefore, respondents cannot comment on Attachment B. Respondents reserve the right to

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 6 Comment
comment when Attachment B is available for review. Because the document has been presented to the
industry without Attachment B, how will Attachment B be presented to the industry? Regarding subrequirement 5.3, it must be revised to clarify that the Planning Coordinator will provide the list of facilities
subject to the Standard to all of the TOs, GOs, and DPs registered in its footprint, not just to those entities that
have facilities on the list.5.2 refers to “Part 1”. As commented on previously in Question 5 and elsewhere,
Part or Sub-requirement should be used for consistency.

Bonneville Power Administration

Requirement R5 is okay, but Part 5.1 adds an additional and useless extra burden to the applicable entities.
The process that the Planning Coordinator is required by this part to have would almost certainly be to simply
apply the criteria in Attachment B to lines and transformers operated below 200kV to determine if they are
critical to the BES. Requiring documentation for such a trivial process results in increased paper work,
additional preparation for an audit, and is a waste of everyone’s time. We suggest deleting Part 5.1.

IRC Standards Review
Committee

We disagree with modifying the requirement until the criteria is identified. Modifying the requirement now
presumes the criteria will have no impact to the requirement. Contrarily, we believe that the criteria may
cause some change to the requirement as well. The criteria in Attachment B along with any necessary
modifications to the associated requirement should be developed by a full standards drafting team. Only the
full standards drafting team could identify equally effective alternatives to the Commission’s directives as they
have made clear they allow in this Order and many others.

MRO's NERC Standards Review
Subcommittee

As noted in Q1 above, a response would be conditional and depend on whether the criteria that will be
established within Attachment B (see R5.1) are reasonable and apply to properly qualified faculties below 200
kV.In addition, the R5 requirement should include wording that limits the scope of the transmission facilities
(line and transformer circuits) to be evaluated to only those transmission facilities that can be tripped by the
relay settings subject to requirement R1. Requirement R5 should also qualify that only the transmission
facilities that are “known” to be associated with the relay settings subject to requirement R1 need to be
evaluated. If the SDT wants to better assure that the Planning Coordinator knows about all of the pertinent
transmission facilities, then they should add a requirement that obligates Transmission Owners, Generator
Owners, and Distribution Providers to provide the Planning Coordinator with a list of the transmission facilities
that are associated with the relay setting subject to requirement R1.

E.ON U.S. LLC

See comments for item #1.

Transmission Access Policy
Study Group

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 6 Comment
responsive transmission phase protection system, aside from a DP that is also a TO and has such a phase
protection system because of its TO function. There is thus no reason to include DPs as potentially
applicable entities.If the SDT retains DPs on the list of potentially applicable entities, it should at minimum
clarify Requirement R5.3 to state that the Planning Coordinator will provide the list of facilities subject to the
standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who have facilities
on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.

American Transmission
Company

As noted in Q1 above, an affirmative response would be conditional and depend on whether the criteria that
will be established within Attachment B (see R5.1) are reasonable and apply to properly qualified facilities
below 200 kV.In addition, the R5 requirement should include wording that limits the scope of the transmission
facilities (line and transformer circuits) to be evaluated to only those transmission facilities that can be tripped
by the relay settings subject to requirement R1. Requirement R5 should also qualify that only the transmission
facilities that are “known” to be associated with the relay settings subject to requirement R1 need to be
evaluated. If the SDT wants to better assure that the Planning Coordinator knows about all of the pertinent
transmission facilities, then they should add a requirement that obligates Transmission Owners, Generator
Owners, and Distribution Providers to provide the Planning Coordinator with a list of the transmission facilities
that are associated with the relay setting subject to requirement R1.

TSGT System Planning Group

While we agree that the purpose of Requirement R5 is beneficial, there is much confusion about registration
and responsibilities of Planning Coordinators. Though the FERC order proposes that planning coordinators
perform the test developed herein, there is also flexibility in how NERC can achieve the same result. We
believe that the Regional Entity (or the Reliability Coordinator, as was included in the System Protection and
Control Task Force recommendation) should be the responsible functional entity for determining which
elements operated at less than 200 kV need to meet Requirement R1. The Region was responsible for
determining operationally significant facilities during the “Beyond Zone 3” process.

NV Energy

This approach is not yet an acceptable and effective method of meeting the directive of paragraph 69.
Whether it becomes an acceptable and effective method of meeting the directive will depend on the content of
Attachment B. I’ll reserve specific judgment and concerns until Attachment B is available for comment.

NPPD

Attachment B has not even been developed.

Idaho Power - System Protection

It is not acceptable or effective until Attachment B is completed and available for review.

Kansas City Power & Light

Do not agree with the approach in R5 and R5.1. This proposes to establish the criteria by which Reliability

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 6 Comment
Coordinators will determine facilities critical to the reliability of the BES. There are a variety of differing, and
often complex, operating conditions that dictate the need for transmission facilities. The TPL standards
require extensive studies of the transmission system be performed under steady state and dynamic
conditions to understand and identify sensitive areas of the transmission system and enable Reliability
Coordinators to identify flowgates in their respective regions. In light of the Reliability Coordinators
awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to the
Reliability Coordinators additional criteria.In addition, in R5.3, do not agree that the Regional Entity be
included as a recipient of the list of transmission facilities. By NERC definition, the Regional Entity is the
Compliance Monitor and Enforcement Authority for the NERC Reliability Standards and is not an operating
entity. It is inappropriate to include Regional Entities as an entity to provide this information outside of the
audit process established by the NERC Rules of Procedure. By definition, in the NERC Reliability
Terminology, the Regional Entity is a compliance enforcement agent and not an operating organization of the
Bulk Power System, and, therefore, has no operating reason to obtain this information. See definition
below:Regional Entity - The term ‘regional entity’ is defined in Section 215 of the Federal Power Act means an
entity having enforcement authority pursuant to subsection (e)(4) [of Section 215]. A regional entity (RE) is an
entity to which NERC has delegated enforcement authority through an agreement approved by FERC. There
are eight RE’s. The regional entities were formed by the eight North American regional reliability organizations
to receive delegated authority and to carry out compliance monitoring and enforcement activities. The
regional entities monitor compliance with the standards and impose enforcement actions when violations are
identified.

Independent Electricity System
Operator

We are unable to assess its acceptability and effectiveness until Attachment B is developed.

Utility Services

The proposed method of identifying facilities to which the standard will apply may be reasonable, though we
cannot comment definitively until a draft of Attachment B is available. The standard should not be applicable
to DPs, however. We have been unable to find or think of an example in which a DP would have a loadresponsive transmission phase protection system , aside from a DP that is also a TO and has such a phase
protection system because of its TO function. There is thus no reason to include DPs as potentially
applicable entities.If the SDT retains DPs on the list of potentially applicable entities, it should at minimum
clarify Requirement R5.3 to state that the Planning Coordinator will provide the list of facilities subject to the
standard to all of the TOs, GOs and DPs registered in its footprint, not just to the entities who have facilities
on the list. It is important that DPs who do not have facilities on the list have documentation from the
Planning Coordinator demonstrating that fact.

Long Island Power Authority

LIPA understands the drafting team’s rationale, however, believes that the proposed method in Attachment B

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 6 Comment
should be developed before providing comments.

Ameren

See our response to Question 1

American Electric Power

Please refer to our comment under question number 1. AEP reserves the right to provide additional
comments once Attachment B has been drafted and supplied for industry review.

ERCOT ISO

ERCOT ISO respectfully asserts that the changes in this standard need more thorough discussion. This
standard is incomplete without the Attachment B and the intent of the requirements is not explicitly clear. A
standard drafting team (not a SAR SDT) needs to develop Attachment B through discussion of the entire
process that will meet Order 733 directives. Attachment B is a critical component needed to assess R5 and
provide further feedback. Requirement 5 needs to be reworded for clarity. The standard drafting team
assigned to this project needs to work closely with the Reliability Coordination SDT (Project 2006-06), which
is tasked with defining critical facilities or identifying criteria for developing a list of critical facilities.ERCOT
ISO disagrees with the use of the phrase ‘facilities that are critical’ in this requirement. A requirement to
create a list of critical facilities should not be addressed in this standard.

Duke Energy

We don’t have Attachment B yet, and the standard development timeline has the standard being submitted to
FERC in March of 2011, which we believe is an unreasonable timeline.

Pepco Holdings, Inc - Affiliates

Yes

FirstEnergy

Yes

Although we agree that R5 is the appropriate requirement to reference the criteria to be used, it is still to be
determined if we agree with the criteria since it is still being developed.

Consumers Energy

Yes

We are concerned about the criteria still undergoing development, and will offer any relevant comments on
that criteria when it is published.

Arizona Public Service Company

Yes

Dominion Electric Market Policy

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

PacifiCorp

Yes

Southern Company

Yes

ComEd

Yes

Manitoba Hydro

Yes

ISO New England Inc.

Yes

ITC Holdings

Yes

Question 6 Comment

Yes
Xcel Energy
Wisconsin Electric

November 1, 2010

Yes
No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
7.

Summary Consideration:
Three-fourths of commenters believe the addition of section 1.6 in Attachment A is not an acceptable and effective method of meeting this
directive. More than one-half of commenters believe that addressing the directive in the proposed manner will have a negative impact on reliability
of the bulk electric system. The SDT agrees that addressing the directive in the manner proposed in the first posting will have the unintended
consequence of impacting the dependability and security of certain protection systems. The SDT has revised the draft standard to address the
following concerns noted by commenters.
•

More than one-half of commenters noted that the proposed modification would require overcurrent fault detectors applied to supervise
distance (impedance) elements to meet the relay loadability requirements which would have a detrimental impact on reliability. Setting these
fault detectors to meet PRC-023 would restrict the ability of some distance elements to trip for end-of-zone faults, particularly on weak source
systems. Eliminating the fault detector to avoid this concern would have the negative impact of making the protection system susceptible to
undesired tripping during close-in faults on adjacent elements. Some commenters further noted that many microprocessor relays have
inherent overcurrent supervision of impedance elements which cannot be disabled.

•

Several commenters noted that the standard should apply to protective systems and not to individual components of protective systems and
that compliance should be based on the ability of the protective system as a whole to meet the performance criteria established by the
standard. Some commenters also noted that a clarification is required that “protective functions” applies only to those protective relay
elements that would respond to non-fault or load conditions and could issue a direct trip.

•

Some commenters noted their belief that the modification goes well beyond the Commission’s concern and they proposed alternatives they
believe would be equally effective and efficient approaches to addressing the Commission’s reliability concerns.

In response to these concerns, in particular the negative impact on reliability associated with the proposed modification, the SDT has modified
section 1.6 to include “1.6.
Supervisory elements associated with current based communication assisted schemes where the scheme is
capable of tripping for loss of communications.” The SDT also modified the second bulleted item in section 2.1 to add the clause, “except as noted
in section 1.6 above.”
Some commenters expressed concern that the proposed modifications would require the overcurrent element in a switch-on-to-fault (SOTF)
scheme to be subject to the relay loadability criteria, in conflict with the SPCTF technical paper that indicates there is no suggested loadability
criterion if the voltage arming threshold is set low enough. Some commenters expressed concern that the proposed modification could negatively
jeopardize reliability by resulting in an operational decision to open breakers upon loss-of-potential to a protection system. These commenters
note that it would be preferable to leave the element in-service with fast tripping enabled for a fault until the loss-of-potential condition can be
diagnosed and corrected. The SDT believes that the modifications to section 1.6 noted above remove the unintended consequence of the original
modifications that could have required overcurrent functions in all SOTF schemes and overcurrent functions used to supervise distance elements
to meet Requirement R1.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
One commenter proposed that the requirement for setting supervising relays be 115 percent of the facility rating nearest to a 4-hour duration
rather than the 150 percent threshold established for other phase protective relay settings that may limit transmission system loadability. The SDT
believes that with the modifications to section 1.6 noted above the same setting requirements are appropriate for all protective functions listed
under section 1 of Attachment A. The SDT believes this is appropriate and necessary to meet the reliability objective of this standard.
One commenter noted that this directive needs to be addressed by a full standard drafting team to adequately address this directive and identify
equally effective alternatives to the Commission’s directives. Another commenter recommended that the NERC System Protection and Control
Subcommittee (SPCS) be engaged to investigate this issue and produce a white paper or other document describing any unintended
consequences of implementing the FERC directive. The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been
reconvened to address the directed modifications to the standard. The SDT believes that the issues indentified in Order No. 733 can be
addressed adequately by this SDT with industry stakeholder input through the NERC Standard Development Process. The NERC SPCS will be
consulted to address the potential for unintended consequences associated with the proposed modifications to implementing the directives from
Order No. 733.

Organization
Pepco Holdings, Inc - Affiliates

November 1, 2010

Yes or No

Question 7 Comment

We do not agree with the proposed wording of Section 1.6 of Attachment A which makes the standard apply
to “Protective functions that supervise operation of other protective functions in 1.1 through 1.5”. The
standard should apply to “protective systems” not individual components of protective systems. Compliance
should be based on the ability of the “protective system” as a whole to meet the performance criteria
established by the standard. Delving into the details of individual scheme designs and supervising element
operation goes well beyond the purpose and scope of this standard.In paragraph 251 of Order 733 the
Commission “expressed concern that section 3.1 could be interpreted to exclude certain protection systems
that use communications to compare current quantities and directions at both ends of a transmission line,
such as pilot wire protection or current differential protection systems supervised by fault detector relays” and
requested comment on “whether it should direct the ERO to modify section 3.1 to clarify that it does not
exclude from the requirements of PRC-023-1 pilot wire protection or current differential protection systems
supervised by fault detector relays.” The Commission reiterated again in paragraphs 266, 268, and 270 their
concern with not including supervising elements associated with “current differential schemes” to prevent
them for operating on loss of communications. That being said, the proposed revision to Attachment A to
include supervising elements for all protective functions in 1.1 through 1.5 goes well beyond addressing the
Commission’s concern. We believe the Commission’s concern could be addressed by simply modifying
Attachment A by deleting proposed section 1.6 and adding a new section 1.5.5 “Line current differential
schemes, including supervising overcurrent elements”. The SDT’s current proposed wording for Section 1.6
would require the overcurrent element in a switch-on-to-fault scheme to be subject to the loadability criteria.
However, the NERC SPCTF in their June 7, 2006 technical paper “Switch-on-to-Fault Schemes in the Context

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment
of Line Relay Loadability” indicated there is no suggested loadability criterion if the voltage arming threshold is
set low enough. Similarly, fault detectors which supervise distance elements would be subject to the
loadability standard. However, there are no criteria established on how to set these elements, particularly on
weak source systems, or zone 3 applications, where in order to reliably detect faults at the end of the zone of
protection may require setting the supervising fault detector below 150% of line rating. The NERC SPCTF in
their June 7, 2006 technical paper “Methods to Increase Line Relay Loadability” provided recommendations to
increase loadability of distance elements through various techniques, such as the use of load encroachment
elements or blinders, but does not specifically address setting of supervising elements. In fact, at present,
there is no reliability standard requiring the use of supervising elements, and some newer microprocessor
relays do not even employ supervising fault detectors on their distance elements. FERC in their Order 733
stated “As with our other directives in this Final Rule, we do not prescribe this specific change as an exclusive
solution to our reliability concerns regarding the exclusion of supervising relay elements. As we have stated,
the ERO can propose an alternative solution that it believes is an equally effective and efficient approach to
addressing the Commission’s reliability concerns.”In summary, we believe that addressing the Commission’s
concern regarding supervising elements on current differential schemes, as described in our second
paragraph above, would satisfy the intent of Order 733, while not imposing unnecessary additional restrictions
on what has proven historically to be extremely reliable protection practices.

PSEG Companies

In attachment A was added a new requirement, item 1.6. We not agree with this. Sometimes these elements
have to be set lower than the criteria. As long as the protection system as a whole does not trip the line, then
that should meet the criteria. Individual elements that supervise tripping element should NOT be part of the
standard.

Bonneville Power Administration

Here we have a situation where the standard is being compromised to satisfy FERC’s misunderstanding of
what a supervising relay is. In Paragraph 266, FERC gives an example of how a line differential relay works
in an attempt to demonstrate why supervisory elements must not operate for load, but instead they clearly
demonstrate their misunderstanding of the details of differential relay operation and what a supervisory relay
is. Modern differential relays will disable the differential function upon loss of communications. If an
overcurrent element is present, it would be used for backup protection, not as a supervisory element. If an
overcurrent element were used to supervise a differential element, the sensitivity of the differential relay would
be lost and the result would be a simple overcurrent relay. FERC’s misunderstanding has resulted in the
improper addition of supervisory relays in Attachment A, Section 1. Sometimes supervisory relays must be
set below maximum loading to obtain the purpose they were intended for. For example, it is often necessary
to set overcurrent supervision of distance relays below the maximum load current of the line so that they will
operate for remote faults. This modification to Attachment A would prohibit that action and make it impossible
to set the supervisory relays to comply with the standard and still provide adequate protection. The

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment
modification to Attachment A is unacceptable.

FirstEnergy

FirstEnergy supports applying PRC-023 to certain supervising relays, such as overcurrent relays that are
enabled only when another (usually communications based) scheme is out of service, or overcurrent relays
that are ANDed with current differential elements that can trip by themselves if the communications path used
by the current differential scheme is compromised. However, it is not clear that a 150% factor is the correct
one to use in this case. Our understanding is that 150% is a combination of an error factor (widely utilized by
industry) of 15% plus a 35% margin to approximate a 15 minute interval rating to give operators time to react
to adverse system conditions. It is unclear that this extra 35% margin is needed for these supervising relays,
when the reliability goal is to prevent relays being continuously picked-up. We recommend that the standard
utilize a 115% margin (rating duration nearest 4 hours) for these types of supervising relays and that this
would be adequate to meet the Commission's stated reliability concerns.However, there are several other
types of schemes that utilize supervising relays where applying PRC-023 would be detrimental to the
reliability of the bulk power system. One widely used case is the supervision of an impedance relay when
there is no communications scheme involved. There are cases where an impedance element/relay which is
set per PRC-023, correctly operates for a fault it is intended to see, but that the actual current value will be on
the order of the line rating, which will result in the scheme not operating if the supervising relay is set as the
commission proposes. The alternative for these types of schemes is to remove the supervision from the
scheme, which will result in the scheme operating purely on the impedance element, which is exactly the
reliability concern that the Commission is trying to address with this directive. However, many microprocessor
relays have inherent overcurrent supervision of impedance elements which cannot be disabled, adding to the
complexity of the issue. Since this is a fairly complex theoretical/technical issue, we recommend that the
NERC System Protection and Control Subcommittee (SPCS) investigate this issue and produce a white
paper or other document describing any unintended consequences of implementing the FERC directive. The
work of the SPCS could also consider equally effective alternatives to meeting the Commission’s directive.

IRC Standards Review
Committee

MRO's NERC Standards Review
Subcommittee

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment
dependability is at risk if fast tripping is not employed. By removing the exclusion, reliability could be
negatively jeopardized. For example, an operational decision to open breakers will be needed for loss of
potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until the
loss of potential condition can be diagnosed and corrected.

Dominion Electric Market Policy

Dominion disagrees with the directive to the ERO to revise section1 to include supervising relays for example,
the fault detectors that we have in electromechanical distance schemes. The impedance relays are set to
meet Reliability Standard PRC-023-1 while the overcurrent fault detector does not trip the transmission line
breaker(s) independently of the impedance relays. Simultaneously meeting full allowance of the line terminal
emergency loading limit and providing adequate sensitivity for detecting line faults with this fault detector will
simply not be achievable for many of our lines.

E.ON U.S. LLC

E.ON U.S. requests a clarification of “protective functions” such that it applies only to those protective relay
elements that would respond to non-fault or load conditions, and could issue a direct trip, upon operation,
during a loss of communication or loss of potential condition.

American Transmission
Company

In Order 733, the Commission cites in footnote 186 (p. 161) the definitions of dependability and security, two
components of reliability for protective relays. The Commission did not recognize that the two tend to be
mutually exclusive. Raising dependability (making sure breakers trip during a fault) can sacrifice some
degree of security (tripping more than is needed).Historically, protection engineers have been biased toward
dependability to ensure the safety of people and equipment. The exclusions allow that to happen. These are
contingency scenarios where protective schemes are compromised. For a second contingency, the
dependability is at risk if fast tripping is not employed. By removing the exclusion, reliability could be
negatively jeopardized. For example, an operational decision to open breakers will be needed for loss of
potential. The corollary would be leaving the element in service with fast tripping enabled for a fault until the
loss of potential condition can be diagnosed and corrected

PacifiCorp

Paragraph No. 264 directs a revision to Section 1 of Attachment A in order to include supervising relay
elements. This change as currently written requires further clarification to meet this directive. For example, a
Distance element is commonly supervised by a phase overcurrent element (Fault detector). If this change
suggests that the overcurrent element has to be set above maximum load, then PacifiCorp disagrees with the
modification. The fault detector will not trip the line by itself; it operates to qualify the distance element
assertion. It is our standard practice to set this element above load where possible, but without restricting the
reach of the distance element. This means that if the fault current at the maximum reach of the distance
element is below load, setting the fault detector above load will restrict the reach of the distance element- this
would compromise the protection scheme. In microprocessor relays where Load encroachment is used this is
even more critical. The Load encroachment function will prevent the distance element from operating in the

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment
load region and a fault detector setting that is sensitive enough can be used safely without the need to set it
above load current to enhance the distance element reach.

Southern Company

The language that has been added to PRC-023 related to the inclusion of protection elements (fault
detectors) supervising protection functions that are subject to the PRC-023-2 requirements is not appropriate
and will likely decrease the reliability of the BES for the following reasons:The tripping logic utilizing
these elements is an AND function, it takes distance element AND the fault detector (FD) to trip. Since all
distance elements meet the loadability criteria, it is not necessary to also ensure FD meet hese
requirements.Setting FD above nominal load point would unnecessarily reduce sensitivity of distance
element and in many cases eliminate the distance element’s ability to protect the very system element it is
designed and intended to protectIt would require very expensive communications based relay
schemes to replicate this lost protection if it is even possible to do so; a long radial line is one instance where
it would not be possibleEliminating the FD would actually reduce Security and Dependability in
electromechanical schemesThere is a whole generation of microprocessor based relays that it is not
possible to eliminate the FD; to effectively take it out of service, one would have to set it to the most sensitive
setting which would violate the loadability criteriaRelays at terminals with high SIR, a weak source
system, and line with large conductors where the far end fault current may be smaller than maximum line
current (similar to Exception 6 of the Relay Loadability Exceptions: Determination and Applications of
Practical Relaying Loadability Ratings, Version 1.1 published November 2004 by the System Protection and
Control Task Force of NERC)Faults with low power factor could present a similar magnitude of line
current as normal high power factor load currents

NPPD

Please remove Attachment A, R1.6. "Protective functions that supervise operation of other protection
functions in 1.1 through 1.5.". If you do not remove R1.6 you must provide a detailed explanation of what
supervise operation means and give examples. Utilities have thousands of relays that have imbedded fault
detective supervision overcurrents for phase distance elements that are set at 0.5 amps or some similar
value. This can not be changed. From your requirement these utilities would have to replace all of these
relays or we would have to lower the Facality rating to 0.5 amp secondary/150%. You are also stating that if
we have an external phase overcurrent fault detector that supervises a phase distance relay that this fault
detector must now have to meet Requirement 1. This is an unacceptable requirement if this is your intent.
You are putting the system at risk if this is your intent. We must set our relays to protect the line. We must
also set fault detectors to pickup for all faults considering N-1 conditions at a minimum where the strongest
source must be remove and the relays must still clear the fault. Please do not lose focus of the purpose:
"Protective relay settings shall be set to reliably detect all fault conditions and protect the electrical network
from these faults". If you have questions on my comments feel free to contact me. Steve Wadas, NPPD, 402
563 5917 Wk.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment

Consumers Energy

The supervising elements addressed within this change may fundamentally be unable to be set in accordance
with the requirements of PRC-023, while still permitting the Protection System to function properly for fault
conditions. The supervising element is usually present to assure that a distance element does not operate
inadvertently for close-in zero-voltage faults near the relay location in the non-trip direction, but does not, by
itself, produce a trip. We appreciate that NERC must respond to this directive, but believe that the change, as
expressed, will be detrimental to reliability.

ComEd

1) Certain relay elements may be thought to be “supervising relay elements”, when their function is specific
and more limited. A very common example would be a phase overcurrent relay that is required to actuate
along with a phase distance relay to cause a trip. In many applications, the phase overcurrent relays function
is only to assure that the phase distance relay will not cause a trip when a line is taken out of service and no
potential restraint is applied to the phase distance relay. Thus, loadability of the phase overcurrent relay is
not a concern. Raising the level of the overcurrent element may negatively impact the fault detecting ability of
the two relays. This is perhaps a limited function supervising relay element. It is complementary to the phase
distance relay which provides the necessary loadability.
2) Although we don’t employ out of step tripping, it would seem that the argument for the overcurrent element
of an out of step tripping scheme would be the same as for the phase distance element.
3) Are there supervisory elements for switch onto fault schemes that could limit loadability?
4) In our experience, relays that supervise overcurrent relays are typically specifically designed to provide
loadability in order to allow the overcurrent relay to provide greater sensitivity without worrying about its
loadability. Thus this requirement would limit the use of such a scheme.
5) FERC’s main example seems to refer to an old style of current differential relaying scheme that is likely not
very widely applied. Most modern current differential schemes use digital communications and will not trip on
loss of communications regardless of the settings of any elements that may be considered to be supervisory
relay elements. The drafting team should consider modifying 1.6 of Attachment A to clarify and more
specifically address the FERC concern. Three suggestions are as follows: 1) 1.6. Protective functions that
supervise operation of other protective functions in 1.5. This is required for communications aided protection
schemes in 1.5 only when those schemes require communication channel integrity to maintain scheme
loadability. 2) 1.6. Protective functions that supervise operation of other protective functions in 1.2 through
1.5. This is required for communications aided protection schemes in 1.5 only when those schemes require
communication channel integrity to maintain scheme loadability. 3) 1.6. Protective functions that supervise
operation of other protective functions in 1.2 through 1.5.

Manitoba Hydro

November 1, 2010

Item 1.6 in Attachment A is not necessary. If the protection functions in 1.1 through 1.5 already meet all the

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment
loadability requirements, the facility would not trip under heavy load condition by the supervising protection
element alone. The directive in paragraph 264 of Order 733 seems to deal with the supervising protection
element on the current differential scheme only. It is still arguable whether it is better to allow tripping of the
line or restrain from tripping during loss communication and heavy loading condition.

Wisconsin Electric

We strongly disagree with this change. Applying the loadability requirement to supervisory functions in
protection system will have an extremely negative effect on BES reliability. With this change, protection
systems will be less dependable, resulting in increased probability of a failure to detect a system fault. This
change should not be implemented.

Long Island Power Authority

LIPA believes that the new wording in 1.6 Attachment A is unnecessary since the existing wording already
complies with the FERC order p.264. Supervisory functions are already part of the protective functions 1.1
through 1.5. Also, this new wording will be subject to varied interpretation and create more confusion.

Ameren

In attachment A - 1.6 is not a tripping function - it’s a supervisory function - it in itself does not trip which is the
description of ‘1’ therefore needs to be elsewhere if kept.

American Electric Power

AEP requests some clarifying information regarding what is envisioned for 1.6 of Attachment A.

ITC Holdings

It appears from the new 1.6 (Attachmnt A) that fault detectors must meet loadability requirements. These do
not trip and must not be included in PRC023. We will not be able to adequately protect longer lines in weak
areas with this requirement in place.

Removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational decision to open
breakers will be needed for loss of potential conditions. The corollary would be leaving the element in service
with fast tripping enabled for a fault until the loss of potential condition can be diagnosed and corrected.

South Carolina Electric and Gas

Item 1.6 of Attachment A needs to be clarified. If the intent is to include protective functions such as fault
detectors then this could possibly lead to relay sensitivity problems when switching contingencies create
weaker systems than normal and a line is faulted. It is unclear why supervisory functions are considered if the
protective functions they supervise will operate in compliance with R1

Xcel Energy

Xcel Energy disagrees with the inclusion of the supervising functions in part 1.6 of Section 1 in Attachment A.
Supervising functions in protection schemes provide security for non-power system fault events and are not
the principal elements for scheme operation. Only principal elements should be considered in the
requirements of the PRCâ€‘023 standard.Functions such as overcurrent fault detectors provide security in the

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 7 Comment
event of a failed potential source or blown secondary fusing. Fault detectors must be set below the minimum
end-of-zone fault with a single system contingency in effect. It is common industry practice to set these
functions at 60â€‘80% of these minimum fault levels and may necessitate a setting that is below the Facility
Rating of a circuit.Increasing the setpoint of an overcurrent fault detector above the Facility Rating will limit the
coverage of the protection system and may impact the system’s ability to protect the electrical network from
Faults. An alternative is to limit the Facility Rating as allowed in Requirement R1.12. However limiting this
Facility Rating places an arbitrary constraint on the circuit and is not justifiable for a non-principal function.
Eliminating the fault detector is not possible in the case of some microprocessor-based relays and if it is
possible, reduces the security of the protective scheme.

Duke Energy

Attachment A has added 1.6 stating “Protective functions that supervise operation of other protective
functions” is included in the standard. We would argue that it is not reasonable to include overcurrent fault
detectors used to supervise distance elements or breaker failure schemes. These relays provide security to
the protection scheme, such as for loss of potential conditions, and do not trip on their own. If these relays
would be set per the standard, it would render the schemes ineffective for many fault conditions. In the case
of electromechanical schemes, the supervising relay could be removed from service which could make the
protection scheme misoperate. In the case of microprocessor relays, the supervising relay is embedded in
logic and can’t be removed.

TSGT System Planning Group

Yes

As we interpret the changes to Attachment A they are acceptable. However, there appears to be uncertainty
about the intent of the drafting team. We interpret the change to 1.6, in conjunction with 2.1, to allow setting
impedance relay fault detector supervisory elements at levels below load current levels. This understanding
comes from the realization that the fault detector elements by themselves do not “trip with or without time
delay, on load current,” a requirement described in 1. The fault detector elements can cause tripping on their
own, but only for conditions of loss of potential or loss of communications, which are both excluded from the
loadability requirements as steted in 2.1.If Tri-State’s interpretation of the intent of Attachment A, Sections 1,
1.6, and 2.1 is incorrect, then we do not agree that this is an acceptable and effective method of meeting this
directive. There are many protection system locations in our system that require the fault detector supervision
elements to be set below load current levels in order for backup impedance relays to operate securely in the
event of loss of potential and to operate dependably for remote faults that inherently have low fault current
magnitudes.

Idaho Power - System Protection

Yes

The order has been met, but there is significant concern about the inclusion of supervisory elements in
protective systems. A supervisory element is not performing a tripping function. As stated in Attachment A
“This standard includes any protective functions which could trip with or without time delay, on load current,
including but not limited to:...”. Supervisory elements, used properly, do not trip for load current.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Northeast Power Coordinating
Council

Yes

Arizona Public Service Company

Yes

NV Energy

Yes

Kansas City Power & Light

Yes

Independent Electricity System
Operator

Yes

ISO New England Inc.

Yes

November 1, 2010

Question 7 Comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
8.

Do you agree that the SDT has addressed the remaining directives: Paragraph 284 to remove the footnote and Paragraph 283 to
modify the implementation plan for sub-100 kV facilities (by revising the Effective Date section of the standard)?

Summary Consideration:
The SDT agrees with several commenters about the proposed language for Effective Dates and has changed the language to the following:
5.1. Requirement R1: the first day of the first calendar quarter after applicable regulatory approvals, except as noted below.
5.1.1

For the addition to Requirement R1, criterion 10, to set transformer fault protection relays and transmission line relays on transmission
lines terminated only with a transformer such that the protection settings do not expose the transformer to fault level and duration that
exceeds its mechanical withstand capability, the first day of the first calendar quarter 12 months after applicable regulatory approvals.

5.1.2

For supervisory elements as described in Attachment A, section 1.6, the first day of the first calendar quarter following 24 months after
applicable regulatory approvals.

5.2. Requirements R2 and R3: the first day of the first calendar quarter after applicable regulatory approvals.
5.3. Requirements R4 and R5: the first day of the first calendar quarter following 24 months after applicable regulatory approvals.
5.4. Requirement R6: the first day of the first calendar quarter 18 months after applicable regulatory approvals.
5.5. Requirement R7: the first day of the first calendar quarter after applicable regulatory approvals.
One comment addressed the issue of a reliability standard superseding previous agreements between registered entities and NERC. The SDT
believes that, by removing the footnote, the standard does not supersede previous agreements because the latest due date for mitigation of
temporary exceptions under the Beyond Zone 3 review was December 31, 2008. Removal of the footnote has no bearing on previous agreements
given that all temporary exceptions have expired.
To address the need for entities to meet the requirements of the standard for facilities identified by the Planning Coordinator in the future, the SDT
added a new requirement (R7).

Organization
Pepco Holdings, Inc - Affiliates

November 1, 2010

Yes or No

Question 8 Comment

We agree with the removal of the footnote regarding temporary exceptions. However, there appears to be a
contradiction between the effective dates for sub 200kV facilities noted in section 5.1.2 (39 months following
regulatory approvals) and 5.1.3 (24 months after being notified by its Planning coordinator). If the planning
coordinator takes the full 18 months to determine the R5 list (per effective date section 5.2) and the TO has
24 months after that to comply, that would be 42 months following regulatory approval, which is in conflict with
the 39 month requirement in 5.1.2. Since the list of sub 200kV facilities may change from year to year, it

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 8 Comment
would seem prudent to make the effective date for those facilities always tied to a defined interval following
being notified by the Planning Coordinator and eliminate the 39 month requirement for sub 200kV facilities
from 5.1.2. Also, since the Attachment B methodology has not yet been determined, it is unclear how many
sub 200kV facilities may fall under these requirements. As such, one cannot yet determine if the proposed 24
months would be sufficient. We propose at least a 36 month interval until the methodology is finalized and
the magnitude of the scope better defined. In addition, if supervising elements are included in the standard
in some form, an implementation schedule (i.e. appropriate effective dates) need to be developed based on
this significant increase in scope and number of facilities to be reviewed.

Bonneville Power Administration

5.1.2 and 5.1.3 both apply to the same systems and should be combined into one sub-requirement. Also,
since the date of the applicable regulatory approval is now established, please consider replacing the cryptic
phrase “at the beginning of the first calendar quarter 39 months following applicable regulatory approval” with
an actual date.

IRC Standards Review
Committee

While we agree removing the footnote is straight forward and addresses one Commission directive, we
believe the other directives need to be addressed by a full standards drafting team to ensure the precise
language is crafted to adequately address the directives. Furthermore, we believe only the full standards
drafting team could identify equally effective alternatives to the Commission’s directives as they have made
clear they allow in this Order and many others. In particular, we believe that only a full drafting team could
adequately assess if any additional time will be needed to comply with the standard for sub-100 kV facilities
particularly when we consider there are some outstanding issues including a regional entity’s critical facilities
list identified in Question 1. Also, we are unable to assess if the two directives are fully addressed absent a
proposed implementation plan.

Kansas City Power & Light

It is inappropriate for this standard to supersede any other agreements and the provisions of those
agreements that have been established between NERC and Registered Entities. The footnote made it clear
those agreements would continue to be honored. Recommend the SDT reinstate the principles established
by the footnote directly into the Effective Dates section to recognize the authority of those agreements.Agree
with the effective dates of 18 months after applicable approvals for R5 and for 24 months after notification by
the Planning Coordinator of a new critical facility.

Independent Electricity System
Operator

We are unable to comment on this in the absence of a proposed implementation plan.

E.ON U.S. LLC

Cannot assess the impact until Attachment B is developed and commented sections above are clarified.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 8 Comment

Manitoba Hydro

Even though this version of the standard does seem to have addressed Paragraph 284 of Order 733, we still
do not agree with the uniform effective date without taking into consideration how many critical circuits or
equipment could be added for an individual utility.

American Electric Power

It is unclear how much time a TO, GO, or DP would have to implement the changes based on the results of
the analysis by the Planning Coordinator. In addition, the Effective Date section is a one-time event upon
regulatory approval. What are the on-going implementation expectations? There should be some allowed
lead beyond initial implementation after facilities are identified by the Planning Coordinator.

ITC Holdings

The new effective dates for 5.1.2 will for the most part be ok. Some of these below 200 kV lines will have to
be reconstructed to be able to have adequate protection and meet the required loadability. It will be difficult to
do this in 39 months. We suggest a mitigation program be required for those lines that will be difficult to meet
the 39 month deadline.

Duke Energy

Until we see the criteria for Attachment B, we can’t agree that 39 months is sufficient time.

ISO New England Inc.

While we agree removing the footnote is straight forward and addresses one Commission directive. In
particular, we believe that only a full drafting team could adequately assess if any additional time will be
needed to comply with the standard for sub-100 kV facilities particularly when we consider there are some
outstanding issues a regional entities critical facilities list identified in Question 1. Also, we are unable to
assess if the two directives are fully addressed absent a proposed implementation plan.

Long Island Power Authority

Northeast Power Coordinating
Council

Yes

FirstEnergy

Yes

MRO's NERC Standards Review
Subcommittee

Yes

Dominion Electric Market Policy

Yes

American Transmission

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 8 Comment

Company
Southern Company

Yes

TSGT System Planning Group

Yes

NV Energy

Yes

NPPD

Yes

Consumers Energy

Yes

Idaho Power - System Protection

Yes

ComEd

Yes

Ameren

Yes

Xcel Energy

Yes

Wisconsin Electric

November 1, 2010

No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
9.

Do you agree that the scope of the proposed standards action addresses the directive or directives?

Summary Consideration:
The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011. However, some commenters
indicated this directive should be included in Phase III since it deals with the subject of relay operations due to power swings.
The SDT reviewed the SAR and determined a modification to the SAR is unnecessary because the SDT already has considered
“islanding” strategies that achieve the fundamental performance for all islands as part of Phase I, although following this
consideration the SDT agrees islanding strategies are best addressed as part of the new standard that will be developed in
Phase III of the project.
Several commenters indicated that the directive from P. 224 is missing from the detailed section of the SAR, but is included in
the table in the back of the SAR. This was an error in the SAR and the SDT has added this directive to the detailed section of
the SAR for Phase I. The new Requirement R5 will support collection of the data necessary for the ERO to address the directive.
The ERO will provide the data upon request, but outside of PRC-023.

Organization
FirstEnergy

Yes or No
No

Question 9 Comment
i.

The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011.
However, this directive should be included in Phase III since it deals with the subject of relay
operations due to power swings.

ii.

The directive from P. 224 is missing from the detailed section of the SAR, but is included in the table
in the back of the SAR.

iii.

As mentioned in our response to Question 7, we do not agree with how the project is proposing to
address the P. 264 directive.

Response: The SDT reviewed the SAR and determined a modification to the SAR regarding P.162 is unnecessary because the SDT already has
considered “islanding” strategies that achieve the fundamental performance for all islands as part of Phase I, although following this consideration the
SDT agrees islanding strategies are best addressed as part of the new standard that will be developed in Phase III of the project.
The reference to P.224 was omitted from the detailed section of the SAR by error. The SDT has added this directive to the detailed section of the SAR
for Phase I. The new Requirement R5 will support collection of the data necessary for the ERO to address the directive. The ERO will provide the data
upon request, but outside of PRC-023.
Please see our response above to your comment regarding P.264
IRC Standards Review

November 1, 2010

We largely believe the scope will allow the drafting team to address the directives. However, we request that

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Committee

Question 9 Comment
the scope be modified to make clear that the drafting team may use equally effective alternatives to address
the Commission’s directives per the Commission in this order and other orders such as Order 693.There is a
discrepancy between the entities listed in the Applicability Section and those checked off in the SAR. The
latter indicates that the SAR is also applicable to the Reliability Coordinator, which we do not believe is
appropriate.

Response: The Standards Process Manual states that a Standard Authorization Request (SAR) is the form used to document the scope and reliability
benefit of a proposed project for one or more new or modified standards or the benefit of retiring one or more approved standards. This SAR is
specific to addressing regulatory directives in Order No. 733. The SAR should only contain the scope and not include how the directives will be met as
it is understood that the directives may be met in an equally effective alternative.
The SDT notes that the SAR contains a list of entities that could potentially be included in the standard, but it is not necessary that the SDT include
each entity in the applicability section of the standard.
MRO's NERC Standards Review
Subcommittee

It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.

See commented sections above. Also, the directive identified in Paragraph 224 was not included in the
detailed description or highlighted in Attachment 1 of the SAR. However it was included in the proposed
modifications as R4.

Response: Thank you for your input.
E.ON U.S. LLC

Response: The reference to P.224 was omitted from the detailed section of the SAR by error. The SDT has added this directive to the detailed section
of the SAR for Phase I. The new Requirement R5 will support collection of the data necessary for the ERO to address the directive. The ERO will
provide the data upon request, but outside of PRC-023. Requirement R5 does not address the directive in P.224 directly as this is a directive to the
ERO to provide data upon request. Since the data is subject to audit, the SDT interprets this to mean that the ERO must gather and have continuously
available a list of facilities using Requirement R1 criterion 12. Requirement R5 ensures that the data is available.
TSGT System Planning Group

As stated in our earlier comments, we believe that some proposals exceed the directives. It is also not clear
how p 162 was addressed in PRC-023-2 as indicated on SAR-3.

Response: The SDT notes that this directive is not addressed in PRC-023-2. The SDT considered “islanding” strategies that achieve the fundamental
performance for all islands as part of Phase I, although following this consideration the SDT agrees islanding strategies are best addressed as part of
the new standard that will be developed in Phase III of the project.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

NPPD

American Electric Power

Question 9 Comment

Refer to our comment under question 1.

Response: Please see our response above to your comment on Question 1.
Pepco Holdings, Inc - Affiliates

Yes

While the scope of the proposed standards action addresses the directive(s) outlined in FERC Order 733 we
believe that there are two significant issues that need to be much more thoroughly investigated before being
included. Those areas are the inclusion of supervising elements in the existing relay loadability standard and
the development of any new standard that would “require the use of protective relay systems that can
differentiate between faults and stable power swings and when necessary phase out protective relay systems
that cannot meet this requirement.”

Response: In response to industry concerns regarding supervisory elements, in particular the negative impact on reliability associated with the
proposed modification, the SDT has modified section 1.6 to state: “1.6.
Supervisory elements associated with current based communication
assisted schemes where the scheme is capable of tripping for loss of communications.” The SDT also modified the second bulleted item in section
2.1 to add the clause, “except as noted in section 1.6 above.” The NERC SPCS will be consulted to address the potential for unintended consequences
associated with the proposed modifications to implementing the directives from Order No. 733.
The issues related to power swings will be addressed in Phase III of this project according to the SAR, and the NERC System Protection and Control
Subcommittee (SPCS) and Transmission Issues Subcommittee (TIS) are jointly developing a paper, Issues Related to Protective System Response to
Power Swings.
American Transmission
Company

Yes

It addresses the directives per the letter of the order; however, it is not necessarily improving reliability.

Yes

Agree that the SDT has made revisions that attempted to address the FERC directives. Do not agree with all
the proposals by the SDT as indicated by the comments regarding questions 1 through 8.

Response: Thank you for your input.
Kansas City Power & Light

Response: Please see our responses above to your comment on Questions 1 through 8.
Independent Electricity System
Operator

November 1, 2010

Yes

As indicated in our comment submitted under Q1, there is a discrepancy between the entities listed in the
Applicability Section and those checked off in the SAR. The latter indicates that the SAR is also applicable to
the RC, which we do not believe is required.

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 9 Comment

Response: The SDT notes that the SAR contains a list of entities that could potentially be included in the standard, but it is not necessary that the SDT
include each entity in the applicability section of the standard.
Northeast Power Coordinating
Council

Yes

Bonneville Power Administration

Yes

Dominion Electric Market Policy

Yes

Arizona Public Service Company

Yes

PacifiCorp

Yes

Southern Company

Yes

NV Energy

Yes

Consumers Energy

Yes

Idaho Power - System Protection

Yes

ComEd

Yes

Manitoba Hydro

Yes

ISO New England Inc.

Yes

Long Island Power Authority

Yes

ITC Holdings

Yes
Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Duke Energy

Yes

Wisconsin Electric

November 1, 2010

Question 9 Comment

No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
10. Can you identify an equally efficient and effective method of achieving the reliability intent of the directive or directives?

Summary Consideration:

Many comments were offered regarding the directives in Paragraph 150 of Order 733 that NERC “develop a Reliability Standard that
requires the use of protective relay systems that can differentiate between faults and stable power swings and, when necessary, phases
out protective relay systems that cannot meet this requirement,” and suggested that this subject either needs to be addressed via
modification to TPL-001 or that it needs further study. It is notable that this issue is to be addressed in Phase III of this project
according to the SAR, and that the SPCS and TIS are jointly developing a paper, Issues Related to Protective System Response to
Power Swings.
Many other commenters repeated comments that were offered in response to other questions.

Organization

Yes or No

American Electric Power

Question 10 Comment

Not at this time, but AEP would like to consider all viable options throughout the standard development
process.

Regarding the directive of Par. 264, since this is a fairly complex theoretical/technical issue, we recommend
that the NERC System Protection and Control Subcommittee (SPCS) investigate this issue and produce a
white paper or other document describing any unintended consequences of implementing the FERC directive.
The work of the SPCS could also consider equally effective alternatives to meeting the Commission’s
directive.

Response: Thank you for your input.
FirstEnergy

Response: The NERC SPCS will be consulted to address the potential for unintended consequences associated with the proposed modifications to
implementing the directives from Order No. 733.
IRC Standards Review
Committee

We are not prepared at this time to offer equally efficient and effective alternatives. Rather, we believe this is
the purpose for convening a full drafting team and that the drafting team should propose their alternatives.

Response: The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been reconvened to address the directed modifications to the
standard. The SDT believes that the issues identified in Order No. 733 can be addressed adequately by this SDT with industry stakeholder input

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 10 Comment

through the NERC Standard Development Process.
Dominion Electric Market Policy

Since there is no question that asks if there are other concerns with this draft, I will add one here..... R2
should be modified to read “The Each Transmission Owner, Generator Owner, or and Distribution Provider
that uses a circuit capability with the practical limitations described in Requirement R1, Settings1.6, R1.7,
R1.8, R1.9, R1.12, or R1.13 shall use the calculated circuit capability as the Facility Rating of the circuit and
shall forward this information to the Planning Coordinator, Transmission Operator, and Reliability Coordinator.
The burden for acknowledging agreement or specifying reasons for disagreement should reside with the
Planning Coordinator, Transmission Operator, and Reliability Coordinator. Suggest SDT develop additional
requirements similar to those in FAC-008 @ R2 and R3.

Response: This proposal is outside the scope of the SAR that is intended to limit the project to addressing the directives in Order No. 733. This
suggestion could be made when the standard is reviewed during the required 5-year review of the standard.
ISO New England Inc.

Response: The Relay Loadability Standard Drafting Team that developed PRC-023-1 has been reconvened to address the directed modifications to the
standard. The SDT believes that the issues indentified in Order No. 733 can be addressed adequately by this SDT with industry stakeholder input
through the NERC Standard Development Process.
NV Energy

NERC's proposed Phase I, II, II process seems reasonable.

Response: Thank you for your support.
ComEd

No, other than the comments provided for question 7.

Response: Please see our responses above to your comment on Question 7.
Dominion Electric Market Policy

PacifiCorp

Southern Company

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

NPPD

Idaho Power - System Protection

Kansas City Power & Light

ITC Holdings

Question 10 Comment

No other comments.

No
Northeast Power Coordinating
Council

Duke Energy

Bonneville Power Administration

TSGT System Planning Group

Yes

We included specific proposals in our comments to questions 2, 4, 5, and 6.

Response: Please see our responses above to your comment on Questions 2, 4, 5, and 6.
Manitoba Hydro

Yes

The effective date can be dependent upon how many critical circuits or equipment are identified for each
individual company.

Response: The SDT considered this possibility in developing effective dates for each requirement in the standard.
Consumers Energy

Yes

NERC should, again, oppose the FERC directive in paragraph 264, since, as explained above, this directive is
both unnecessary and detrimental to reliability.

Response: In response to industry concerns, in particular the negative impact on reliability associated with the proposed modification, the SDT has
modified section 1.6 to state: “1.6. Supervisory elements associated with current based communication assisted schemes where the scheme is
capable of tripping for loss of communications.” The SDT also modified the second bulleted item in section 2.1 to add the clause, “except as noted in
section 1.6 above.”

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
Long Island Power Authority

Yes or No

Question 10 Comment

Yes

Involving industry working groups such as IEEE, EPRI, etc who have proven technical experts will also help in
effectively achieving reliability.

Response: The NERC System Protection and Control Subcommittee (SPCS) will be consulted to address the potential for unintended consequences
associated with the proposed modifications to implementing the directives from Order No. 733.
Pepco Holdings, Inc - Affiliates

Yes

Regarding the response of protective relay systems to stable power swings, Draft 5 of TPL-001-2
Requirement R4 (stability assessment) section 4.3.1 requires a contingency analysis be performed which
includes “tripping of transmission lines and transformers where transient swings cause protection system
operation based on generic or actual relay models.” Therefore the impact of power swings on relay operation
is already addressed in TPL-001. If the tripping of a line is identified during this study phase the impact of the
line trip is assessed to ensure the system meets the performance criteria identified in Table 1. If not,
mitigating measures would be required, such as modifying that protection scheme to prevent its operation
during a stable power swing. However, this would be done on a case by case basis when identified. This
seems a much more prudent approach than to require “all protection systems be modified to prevent
operation during stable power swings.” That would be similar to requiring the re-conductoring all lines so that
they could never experience an overload. Also, Appendix F of the “PJM Relay Subcommittee Protective
Relaying Philosophy and Design Standards” employs a methodology to address relay response during power
swings by calculating a transient load limit for the relay instead of just the steady state limit identified in PRC023. The relay loadability is evaluated at the maximum projection along the +R axis (the most susceptible
point for swings to enter) rather than at a 30 degree load angle. Various multiplying factors are used to
account for the relay operating time delay. This methodology of calculating relay transient loadability limits,
which was developed by the PJM Relay Subcommittee over 30 years ago, has worked extremely well in
eliminating relay operations during stable power swings. In summary, there are other methods to evaluate
and improve the performance of protection systems during power swings short of hardware replacements. All
options should be evaluated

Response: The issues related to power swings will be addressed in Phase III of this project according to the SAR, and the NERC System Protection
and Control Subcommittee (SPCS) and Transmission Issues Subcommittee (TIS) are jointly developing a paper, Issues Related to Protective System
Response to Power Swings.
MRO's NERC Standards Review
Subcommittee

Yes

On the topic of ‘adding in’ - listing and evaluating the transmission facilities below 200 kV, we propose the
inclusion of qualifications that prevent the consideration and evaluation of irrelevant facilities (e.g. facilities
that are not tripped by the applicable relay settings).

Response: The SDT believes the proposed criteria in Attachment B defining the test Planning Coordinators will use to determine which facilities must

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 10 Comment

comply with PRC-023 will address the commenters concerns.
American Transmission
Company

Yes

Response: The SDT believes the proposed criteria in Attachment B defining the test Planning Coordinators will use to determine which facilities must
comply with PRC-023 will address the commenters concerns.
ERCOT ISO

ERCOT ISO thinks a standard drafting team can evaluate the Order 733 directives, work in conjunction with
other Standard Drafting Teams already addressing some aspects of critical facilities, may be able to more
succinctly arrive at an equally efficient and effective method of achieving the intent of the directive(s). The
coordination between teams is vital to avoid confusion and possible overlap.

Response: The SDT has addressed the specific comment regarding coordination with the Reliability Coordination SDT (Project 2006-06) by modifying
the standard to replace the phrase “critical to the reliability of the bulk electric system” with “that must comply with this standard.” The SDT believes
that the directed modifications to PRC-023-1 contained in Order No. 733 are unique to this standard and do not require coordination with other SDTs.
E.ON U.S. LLC
Wisconsin Electric

November 1, 2010

Yes
No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
11. Do you agree with the scope of the proposed standards action?

Summary Consideration:
Several commenters indicated that they do not agree with the scope of the proposed standards action based on the technical
comments submitted against many of the proposed actions submitted in response to the original FERC NOPR on PRC-023. In
response, the SDT indicated that FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued
directives in Order No. 733 that the SDT must address.
Several commenters indicated that the scope of the SAR should be modified to make clear that the drafting team may use
equally effective alternatives to address the Commission’s directives per the Commission in this order and other orders such as
Order 693. In response the SDT cited the Standards Process Manual. The Standards Process Manual states that a Standard
Authorization Request (SAR) is the form used to document the scope and reliability benefit of a proposed project for one or
more new or modified standards or the benefit of retiring one or more approved standards. This SAR is specific to addressing
regulatory directives in Order No. 733. The SAR should only contain the scope and not include how the directives will be met as
it is understood that the directives may be met in an equally effective alternative.
Many comments received indicated that the proposed modifications to PRC-023 reach beyond the directives without specifying
which particular modifications are problematic. The SDT worked carefully to not go beyond the directives.
A commenter indicated that the scope should address apparent conflicts in timing of requirements posed by the standard. A
newly proposed implementation plan will be proposed in the formal posting of PRC-023 that allows transition time for entities to
become compliant with the modified requirements. The SDT agrees that a revised implementation plan is necessary and will
post it for review by the industry during the next posting of the standard.
Some commenters suggested that several parts of the standard go too far (Appendix A R1.10) and will require documenting
faults and clearing times to prove the fault duty of transformer connections. They also suggested the requirements to deal with
out of step blocking relays should go in phase 3 and not in this standard. The SDT believes that evidence such as coordination
curves or summaries of calculations are sufficient to demonstrate that relays set per criterion 10 do not expose the transformer
to fault levels and durations beyond those indicated in the standard. The potential for out-of-step blocking protection elements
to assert due to system load conditions already is addressed in PRC-023-1. Moving this subject from Attachment A to an
explicit requirement in PRC-023-2 does not alter the requirement that already exists for Transmission Owners, Generator
Owners, and Planning Coordinators. The SDT also notes that operation of out-of-step blocking elements due to system load
conditions is outside the scope of Phase III of this project which is to address the directive regarding protection system
operation during power swings.
Some commenters noted believe that removal of exclusion 3.1 in Att. A, will lead to reduced reliability because an operational
decision to open breakers will be needed for loss of potential conditions. The SDT has modified section 1.6 in response to
concerns that applying the standard to elements such as fault detectors that supervise directional distance elements could have

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
a negative impact on reliability. The SDT has modified section 1.6 to include “Supervisory elements associated with current
based communication assisted schemes where the scheme is capable of tripping for loss of communications.” The SDT also
modified the second bulleted item in section 2.1 (formerly 3.1) to add the clause, “except as noted in section 1.6 above.”

Organization
Pepco Holdings, Inc - Affiliates

Yes or No
No

Question 11 Comment
We do not agree with the scope of the proposed standards action for numerous reasons. The documented
responses to the original FERC NOPR on PRC-023 from numerous sources, including NERC and EEI,
together make a rather convincing technical argument against many of these proposed actions. We support
these technical arguments, which for the sake of brevity will not be repeated here. In addition, we have
provided comments and objections on specific portions of the proposed standards action in our responses to
questions 1 through 10 above.

Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
MRO's NERC Standards Review
Subcommittee

We agree that the topics of generator relay loadability and power swing protective relaying should be referred
to in other separate standards. While we acknowledge that it is in everyone’s best interest to respond to the
FERC directives, there are numerous technical flaws that need to be resolved in their request. Forming a
team and spending considerable resources will not gain industry acceptance to these directives.

Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
American Transmission
Company

Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
PacifiCorp

It is very difficult to comment on test parameters that have not been determined.

Response: The criteria that Planning Coordinators will use to determine which facilities must comply with PRC-023 were posted on September 23 for a

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 11 Comment

20-day informal comment period. The SDT has reviewed Requirement R5 and the criteria in Attachment B and has made conforming changes to ensure
no conflicts exist. The full standard with Attachment B will be posted for a 45-day formal comment period.
Kansas City Power & Light

Do not agree with all the proposals by the SDT as indicated by the comments regarding questions 1 through
8.

Response: Thank you for your comments. Please see the summary considerations above.
ISO New England Inc.

We largely believe the scope will allow the drafting team to address the directives. However, we request that
the scope be modified to make clear that the drafting may use equally effective alternatives to address the
Commission’s directives per the Commission in this order and other orders such as Order 693.
Response: The Standards Process Manual states that a Standard Authorization Request (SAR) is the
form used to document the scope and reliability benefit of a proposed project for one or more new or
modified standards or the benefit of retiring one or more approved standards. This SAR is specific to
addressing regulatory directives in Order No. 733. The SAR should only contain the scope and not
include how the directives will be met as it is understood that the directives may be met in an equally
effective alternative.
The scope should address apparent conflicts in the timing of requirements posed by the standard. It is our
understanding that, based on the final date afforded NERC to develop the criteria for the determination of
sub-200 kV facilities,a newly proposed implementation plan will be offered to allow the Planning Coordinators
an appropriate time frame to apply the criteria to determine the “critical” facilities below 200 kV. The
implementation plan should cause the effective date for circuits described in 4.1.2 and 4.1.4 to be changed
from “39 months following applicable regulatory approvals” to a date linked to the Planning Coordinators
schedule to provide a list to its TOs, GOs and DPs.
Response: The SDT modified the implementation schedule for those requirements that the SDT has
modified to address a FERC directive in Order No. 733. In addition, the SDT added a requirement, now
Requirement R7, that requires the Transmission Owners, Generator Owners, and Distribution
Providers to implement Requirement R1, Requirement R2, Requirement R3, and Requirement R4, and
Requirement R5 for each facility that is added to the Planning Coordinator’s list of facilities that must
comply with this standard pursuant to Requirement R6, Part 6.12 by the later of the first day of the
second calendar quarter after 24 months following notification by the Planning Coordinator of a
facility’s inclusion on such a list, or the first day of the first calendar quarter of the year in which
criterion B6 first applies.

Duke Energy

November 1, 2010

o The SAR states that Paragraph 162 is part of Phase I, but the new standard addressing stable power

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 11 Comment
swings is Phase III.

Response: The SAR shows the directive from P. 162 as part of Phase I to be implemented by March 18, 2011. However, this directive should be
included in Phase III since it deals with the subject of relay operations due to power swings. The SDT reviewed the SAR and determined to leave this in
Phase I because the directive says to consider “islanding” strategies that achieve the fundamental performance for all islands in developing the new
Reliability Standard addressing stable power swings but agrees that a new standard will be developed for this in Phase III of the project.
ITC Holdings

Several parts of the standard go too far (Appendix A R1.10) and will require us to document faults and
clearing times to prove the fault duty of transformer connections. Also the requirements to deal with out of
step blocking relays should go in phase 3 and not in this standard.

Response: This is part of the existing, approved standard and the SDT cannot change this part of the standard since it is not associated with a
directive in Order No. 733. The SDT removed out-of-step blocking from Requirement R1. The requirement pertaining to evaluation of out-of-step
blocking protection has been moved to a separate requirement (now Requirement R2) to more clearly delineate this requirement from assessment of
relay loadability of phase protective relays. Phase III of this project will address protective relays operating unnecessarily due to stable power swings
and is not intended to address out of step blocking relays.
No

Response: The SDT has modified section 1.6 in response to concerns that applying the standard to elements such as fault detectors that supervise
directional distance elements could have a negative impact on reliability. The SDT has modified section 1.6 to include “Supervisory elements
associated with current based communication assisted schemes where the scheme is capable of tripping for loss of communications.” The SDT also
modified the second bulleted item in section 2.1 (formerly 3.1) to add the clause, “except as noted in section 1.6 above.”
E.ON U.S. LLC

NPPD

FirstEnergy

Yes

We agree that this standards action is necessary to meet the FERC directives, but have some concerns as
we have stated in previous responses above.

Response: Thank you for your comments. Please see the summary considerations above.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization
TSGT System Planning Group

Yes or No
Yes

Question 11 Comment
We agree that the scope meets the FERC directive, but some of the proposals in the proposed standard
reach beyond the directive.

Response: Without additional details, the SDT cannot address the issues that the commenter has with the specific modifications to PRC-023-2
intended to address the FERC directives.
Independent Electricity System
Operator

Yes

We general agree with the proposed action but there are detailed changes that we have comments on, which
are noted in our comments under Q1 to Q8

Response: Thank you for your comments. Please see the summary considerations above.
ComEd

Yes

Yes, given that we assume that NERC must address all the FERC directives whether or not NERC or the
industry agrees with them.

Response: FERC considered the comments submitted to the original FERC NOPR on PRC-023 and issued directives in Order No. 733 that the SDT
must address.
Long Island Power Authority

Yes

LIPA agrees with the scope in general. Please consider our comments above for answers to specific issues.

Response: Thank you for your comments. Please see the summary considerations above.
Northeast Power Coordinating
Council

Yes

Bonneville Power Administration

Yes

Dominion Electric Market Policy

Yes

Arizona Public Service Company

Yes

Southern Company

Yes

NV Energy

Yes

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Consumers Energy

Yes

Idaho Power - System Protection

Yes

Manitoba Hydro

Yes

American Electric Power

Yes

Wisconsin Electric

November 1, 2010

Question 11 Comment

No comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
12. Are you aware of any regional variances that we should consider with this SAR?

Summary Consideration:

The majority of the commenters did not identify variances for consideration in the SAR. However, several commenters did point out
that each Regional Entity has its own definition for BES and should be considered when addressing sub-100 kV facilities. In response,
the SDT indicated that Attachment B to the standard will define criteria that Planning Coordinators must apply to determine if a
facility must comply with the standard. In addition, FERC issued a BES NOPR on March 18, 2010 proposing a consistent approach to
defining BES that (i) provides a 100 kV threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed
discretion of a Regional Entity to define BES within its system without NERC or Commission oversight. In the NOPR, the
Commission proposes that a Regional Entity must seek NERC and Commission approval before it exempts a transmission facility
rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the NOPR, NERC submitted
comments that supports the Commission’s objectives of ensuring a common understanding and consistent application of the definition
of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should
be justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner,
NERC proposed that the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and
implement new processes that may be needed, or to enhance existing processes. An Order on the matter has not been issued.
One commenter indicated concern that utilities with long lines and in weak areas will have difficulty protecting their lines and meeting
the required loadability. Regions where there are very rural systems will want to write standards that allow adequate protection for
their systems. Requirement R1 part 13 states that: “Where other situations present practical limitations on circuit capability, set the
phase protection relays so they do not operate at or below 115% of such limitations.” This was included in the standard for such cases
where additional criteria are necessary.

Organization
IRC Standards Review
Committee

Yes or No
No

Question 12 Comment
We are not aware of any regional variances per se. However, each regional entity has its own definition for
BES and this needs to be considered when addressing sub-100 kV facilities.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 12 Comment

threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed discretion of a Regional Entity to define BES within its
system without NERC or Commission oversight. In the NOPR, the Commission proposes that a Regional Entity must seek NERC and Commission
approval before it exempts a transmission facility rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the
NOPR, NERC submitted comments that support the Commission’s objectives of ensuring a common understanding and consistent application of the
definition of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should be
justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner, NERC proposed that
the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and implement new processes that may be
needed, or to enhance existing processes. An Order on the matter has not been issued.
ISO New England Inc.

We are not aware of any regional variances per se. However, each regional entity has its own definition for
BES and this needs to be considered when addressing sub-100 kV facilities.

Response: Attachment B to the standard will define criteria that Planning Coordinators must apply to determine if a facility must comply with the
standard. In addition, FERC issued a BES NOPR on March 18, 2010 proposing a consistent approach to defining BES that (i) provides a 100 kV
threshold for facilities that are included in the BES; and (ii) eliminates the currently-allowed discretion of a Regional Entity to define BES within its
system without NERC or Commission oversight. In the NOPR, the Commission proposes that a Regional Entity must seek NERC and Commission
approval before it exempts a transmission facility rated at 100 kV or above from compliance with mandatory Reliability Standards. In response to the
NOPR, NERC submitted comments that support the Commission’s objectives of ensuring a common understanding and consistent application of the
definition of BES across the regions. NERC also supports the Commission’s objective that variations to application of the BES definition should be
justified on the basis of reliability. To ensure these objectives are accomplished in a technically and legally appropriate manner, NERC proposed that
the Commission should rely on the NERC Reliability Standards Development Process to consider, develop and implement new processes that may be
needed, or to enhance existing processes. An Order on the matter has not been issued.
Long Island Power Authority

Yes

NPCC BPS definition based on A10 criteria is a regional variance.

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

ITC Holdings

Question 12 Comment
Utilities with long lines and in weak areas will have difficulty protecting their lines and meeting the required
loadability. Regions where there are very rural systems will want to write standards that allow adequate
protection for their systems.

Response: Requirement R1 part 13 states that: “Where other situations present practical limitations on circuit capability, set the phase protection
relays so they do not operate at or below 115% of such limitations.” This was included in the standard for such cases where additional criteria are
necessary.
Northeast Power Coordinating
Council

Pepco Holdings, Inc - Affiliates

PSEG Companies

Bonneville Power Administration

FirstEnergy

MRO's NERC Standards Review
Subcommittee

Dominion Electric Market Policy

E.ON U.S. LLC

Arizona Public Service Company

American Transmission
Company

PacifiCorp

Southern Company

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

TSGT System Planning Group

NV Energy

NPPD

Consumers Energy

Idaho Power - System Protection

Kansas City Power & Light

Independent Electricity System
Operator

ComEd

Manitoba Hydro

Wisconsin Electric

Ameren

American Electric Power

Question 12 Comment

No
Duke Energy

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
13. Are you aware of any associated business practices that we should consider with this SAR?

Summary Consideration:

Commenters did not indicate that there are any business practices that the team should consider with the SAR.
One commenter suggested that R2 should be modified to read “The Each Transmission Owner, Generator Owner, or and Distribution
Provider that uses a circuit capability with the practical limitations described in Requirement R1, Settings1.6, R1.7, R1.8, R1.9, R1.12,
or R1.13 shall use the calculated circuit capability as the Facility Rating of the circuit and shall forward this information to the
Planning Coordinator, Transmission Operator, and Reliability Coordinator. The burden for acknowledging agreement or specifying
reasons for disagreement should reside with the Planning Coordinator, Transmission Operator, and Reliability Coordinator. The
commenter suggested that the SDT develop additional requirements similar to those in FAC-008 @ R2 and R3. This proposal is
outside the scope of the SAR that is intended to limit the project to addressing the directives in Order No. 733. This suggestion could
be made when the standard is reviewed during the required 5-year review of the standard.

Organization

Yes or No

Northeast Power Coordinating
Council

Pepco Holdings, Inc - Affiliates

PSEG Companies

Bonneville Power Administration

FirstEnergy

IRC Standards Review
Committee

MRO's NERC Standards Review

November 1, 2010

Question 13 Comment

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Question 13 Comment

Subcommittee
E.ON U.S. LLC

Arizona Public Service Company

American Transmission
Company

PacifiCorp

Southern Company

TSGT System Planning Group

Consumers Energy

Idaho Power - System Protection

Kansas City Power & Light

Independent Electricity System
Operator

ComEd

Manitoba Hydro

Wisconsin Electric

ISO New England Inc.

Long Island Power Authority

November 1, 2010

Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set of proposed requirements — Project 2010-13
Organization

Yes or No

Ameren

American Electric Power

ITC Holdings

Question 13 Comment

No
Duke Energy

NPPD

Yes

November 1, 2010

See Question 7.

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project
2010-13)
Please DO NOT use this form. Please use the electronic form located at the link below to
submit INFORMAL comments on the proposed applicability test contained in
Attachment B to PRC-023-2. The electronic comment form must be completed by
October 12, 2010.
If you have questions please contact Stephanie Monzon at Stephanie.monzon@nerc.net
or by telephone at 610-608-8084.
Background Information
NERC Standard PRC-023-1 – Transmission Relay Loadability was approved by FERC as
mandatory and enforceable in March 2010, with direction that NERC make a number of
changes.
The Standard Drafting Team made changes to PRC-023-1 to address the several directives
from Order 733 and posted the proposed changes for comment from August 19, 2010 –
September 19, 2010. The proposed changes did NOT include Attachment B to the standard
as it was at the time still a work in progress. Attachment B is intended to contain the test
that the Planning Coordinators must use to determine whether a sub-200kV facility is critical
to the reliability of the Bulk-Power System. The inclusion of a test is a directive in Order No.
733:
• p. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.
Requirement R5 (previously R3) of PRC-023-2 states:
R5. Each Planning Coordinator shall apply the criteria in Attachment B to determine which
of the facilities (transmission lines operated below 200 kV and transformers with low voltage
terminals connected below 200 kV) in its Planning Coordinator Area are critical to the
reliability of the BES to identify the facilities below 200 kV that must meet Requirement R1
to prevent cascading when protective relay settings limit transmission loadability.
[Violation Risk Factor: High] [Time Horizon: Long Term Planning]
5.1 The Planning Coordinator shall have a process to use the criteria established
within Attachment B to determine the facilities that are critical to the reliability of
the Bulk Electric System.
5.2 Each Planning Coordinator shall maintain a current list of facilities determined
according to the process described in Requirement R5 Part 5.1.
5.3 Each Planning Coordinator shall provide a list of facilities to its Regional Entity,
Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution
Providers within 30 calendar days of the establishment of the initial list and within
30 calendar days of any changes to that list.

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Comment Form — Project 2010-10 — Modifications to FAC Standards for Order 729

Applicability Testing Criteria
NERC Reliability Standard PRC-023 — Transmission Loading Availability was developed in
answer to relay loadability problems highlighted during the blackout of 2003. Relay
loadability has been either causal or contributory to a majority of major system
disturbances dating back to the 1965 blackout and beyond. The proposed Standard is
intended to prevent circuits when thermally overloaded from prematurely tripping due to
relay loadability. The concept is to allow some time for system operators to intervene and
alleviate the overloads.
If any circuit trips under adverse conditions, even if the loss of that circuit does not itself
cause a cascade, the resultant weakened transmission system leaves the bulk electric
system more exposed to possible cascading outages. Therefore, applicability of PRC-023
should not only be for operationally significant circuits that could cause a cascade, but also
for circuits that are prone to overloads (relievable through operator action) during
contingencies.
Planning coordinators test for conformance with the TPL standards through various
contingency analyses that should prevent critical circuits from becoming overloaded. The
TPL criteria contingencies studied normally screen for susceptibility to cascading and system
instability. However, overloading of circuits for short periods of time is permissible, and
assumes operator action can alleviate such overloads in a timely fashion. Although the
planning tests are fairly rigorous they are usually limited to N-1 or N-2 level contingencies.
However, it is for the unforeseen combinations of outages that we want assurance that
circuits would not trip for relay loadability reasons.
The recommendations stemming from the 2003 blackout called for review of circuits 200 kV
and above. Logically, all circuits, including those below 200 kV, that are operationally
significant to the reliability of the bulk electric system (BES) should be tested for
susceptibility.
System studies go to great lengths to determine transfer capabilities on critical transmission
interfaces. Planning and operational studies are routinely conducted to determine the
transfer capabilities of circuits such as those that are part of interconnection reliability
operating limits (IROLs), flowgates in the Eastern Interconnection, Commercially Significant
Constraints in the Texas Interconnection, or Rated Paths in the Western Interconnection.
Any circuit that is important enough to reliability to be actively managed to prevent
overloads should also be important enough to prevent it from inadvertently tripping due to
relay loadability for combinations of outages that are not normally tested.
Similarly, any circuit that is operationally significant to nuclear plant off-site power design
criteria for maintaining voltage, regardless of its operating voltage, should also be protected
from inadvertently tripping due to relay loadability for combinations of outages that are not
normally tested.
The relay loadability screening described below offers another layer of defense-in-depth.
Note: These criteria define the family of circuits that would have their protection system
reviewed for conformance to the PRC-023 loadability criteria. If the protection system
passes, no further action is necessary. If it fails, then the condition would have to be
mitigated.

Comment Form — Project 2010-10 — Modifications to FAC Standards for Order 729

Strategy of Testing
The tests for the applicability of PRC-023 should leverage as much existing work as
possible, including existing system analyses routinely performed by the planning
coordinators, transmission planners, and transmission operators, and minimize the creation
of additional analytical workload.
Mitigation Timeframes
If the protection systems of a circuit are tested and found out of conformance with PRC-023
loadability criteria, the protection systems must be mitigated. After the initial application of
these criteria, which will be governed by the standard implementation plan, the following
time frames for mitigation should be used:
•

If found in the planning analyses: circuits should be mitigated within 24 months or
by the time the overload problem would be expected.

•

If found in the normally performed seasonal operational planning analyses:
loadability concerns should be mitigated before the operating time being analyzed.
If not possible to mitigate prior to the operating time being studied, operators should
be made aware of the loadability limitation and operate the system accordingly.

To expedite the project to address the directives from FERC Order No. 733, the Standard
Drafting Team is posting Attachment B to PRC-023-2 for an abbreviated 20-day informal
comment period.
Please note that the posting of Attachment B to PRC-023-2 is an INFORMAL posting.
1. Attachment B is intended to contain the test that the Planning Coordinators must use to
determine whether a sub-200kV facility is critical to the reliability of the bulk power
system. Do you agree that the method proposed in Attachment B is a technically sound
approach to determine whether a sub-200kV facility is critical to the reliability of the
bulk power system?
Yes
No
Comments:

Standard PRC-023-2 – Transmission Relay Loadability
PRC-023 – Attachment B
Criteria
Review each circuit (line and transformer) less than 200 kV needs against the following criteria to
determine if that circuit needs to be evaluated for conformance with PRC-023. If any of the criteria
apply to a circuit, the circuit needs to be evaluated.
1. Each circuit that is a monitored element of a flowgate in the Eastern Interconnection,
Commercially Significant Constraint 1 in the Texas Interconnection, or rated path in the Western
Interconnection.
2. Each circuit that is a monitored element of an IROL.
3. Each circuit that are directly related to off-site power supply to nuclear plants.
4. Each circuit whose outage causes unacceptable voltages (pursuant to plant license design
specifications) on the off-site power bus at a nuclear plant, regardless of its proximity to the
plant.
5. Each circuit agreed to by the Reliability Coordinator, the Planning Coordinator, and Regional
Entity.
Note – This criterion allows the Reliability Coordinator, Planning Coordinator and Regional Entity
additional latitude in designating other circuits that should be tested for conformance to the
relay loadability criteria.
6. Each circuit operated between 100 kV and 200 kV that exceeds its Short Term Emergency Rating
by 15 percent or more as a result of a double contingency (for those combinations selected by
engineering judgment in TPL-003 System Performance Following Loss of Two or More BES
Elements analyses) beyond the requirements of the TPL-003 standard, i.e., loss of a single
circuit, followed by loss of a second circuit, without system adjustments in between.
Note – This Modified TPL C3 contingency reflects a situation where a System Operator may not
have time between two contingencies to make appropriate system adjustments.

In the ERCOT Zonal Protocols (effective through November 30, 2010):
Commercially Significant Constraint (CSC): A constraint in the ERCOT Transmission Grid that is found,
through the process described in Section 7, to result in Congestion which limits the free flow of energy
within the ERCOT market to a commercially significant degree. The reference to Section 7 is to the ERCOT
Zonal Protocols.

Standards Announcement

Abbreviated Informal Comment Period Open
September 23 - October 12, 2010
Now available at: http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
Project 2010-13: Relay Loadability Order
A draft PRC-023 Attachment B has been posted for a 20-day informal comment period through 8 p.m. Eastern
on October 12, 2010.
PRC-023 – Attachment B provides a set of criteria for the Planning Coordinator to use in determining which of
the facilities (transmission lines operated below 200 kV and transformers with low voltage terminals connected
below 200 kV) in its Planning Coordinator Area are critical to the reliability of the bulk electric system to
identify the facilities below 200 kV that must meet specific relay loadability criteria. The criteria proposed in
Attachment B were under field test and not available to the drafting team when the team prepared the other
modifications to PRC-023-1 that were posted through September 19, 2010.
The Standards Committee authorized an abbreviated comment period for this posting to assist the team in
meeting its project schedule. Order 733 directed that the initial set of specific changes to PRC-023-1, including
the criteria addressed in Attachment B, be filed with the Commission by March 18, 2011.
Informal 20-day Comment Period Open through October 12, 2010
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at Monica.Benson@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page:
http://www.nerc.com/filez/standards/SAR_Project%202010-13_Order%20733%20Relay%20Modifiations.html
Transition from Reliability Standards Development Procedure Version 7 to Standard
Processes Manual
In accordance with the Standard Processes Manual approved by FERC on September 3, 2010, the drafting team
is using an “informal” comment period to solicit stakeholder feedback. The new standard development process
allows drafting teams to use informal comment periods. Unlike formal comment periods where a drafting team
provides a response to each comment submitted, with informal comment periods the drafting team provides a
summary response to each question asked on its comment form, but the team is not obligated to provide an
individual response to each comment submitted. The summary response will indicate whether stakeholders
support the proposal and will identify any additional changes made based on stakeholder comments. With
informal comment periods drafting teams are not required to provide an individual response to each comment
submitted. This change to the process is intended to give drafting teams more time to deliberate on technical
issues, as opposed to deliberating on individual responses to comments. Note that while informal comment
periods are allowed in the new standard process for preliminary drafts of proposed standards, formal comment

periods are still required for the final draft of each standard.
Next Steps
The drafting team will post its response to comments received during this period. The drafting team will use
specific feedback from this informal posting to develop a final draft of Attachment B for inclusion in the next
posting of PRC-023-2.
Project Background
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it directed several
changes to that standard and also directed development of one or more new standards within specified time
periods. NERC filed for clarification and rehearing asking for clarity and an extension of time to address the
directives, however without a response to the requests for clarification and rehearing, NERC must adhere to the
deadlines established in Order 733.
The SAR for Project 2010-13 – Relay Loadability Order subdivides the standard development related directives
into three phases. Phase I addresses the specific directives from Order 733 that identified required
modifications to various elements within PRC-023-1. Phase II addresses directives associated with
development of a new standard to address generator relay loadabilty. Phase III addresses directives associated
with writing requirements to address protective relay operations due to power swings.
Applicability of Proposed PRC-023-2
Distribution Providers that own specific facilities (see standard for details)
Generator Owners that own specific facilities (see standard for details)
Planning Coordinators
Transmission Owners that own specific facilities (see standard for details)
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,

Standards Process Administrator, at monica.benson@nerc.net or at 609.452.8060
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Individual or group. (39 Responses)
Name (22 Responses)
Organization (22 Responses)
Group Name (17 Responses)
Lead Contact (17 Responses)
Question 1 (39 Responses)
Question 1 Comments (39 Responses)
Individual
Donna Jordan
California ISO
No
Further clarifications to the criteria in Attachment B are required.
Individual
Robin W. Blanton
Piedmont EMC
Yes
I would like to have a provision in the Standard so that all radial transmission lines are excluded from this requirement
since they are not used for load transfer. Otherwise, a lot of utilities will have to comply wiht this Standard by stating that
we do not have any critical lines and have a letter from the TO stating that we don't have any critical lines.
Individual
Michael Gammon
Kansas City Power & Light
No
Do not agree with the approach in R5 and R5.1 in proposed Standard PRC-023-2 to dictate to the Planning Coordinator
additional criteria beyond the TPL Standards to identify operating sensitivities. The proposed Appendix B proposes to
establish additional considerations of facilities by which the Planning Coordinator must determine if those facilities are
critical to the reliability of the BES. There are a variety of differing, and often complex, operating conditions that dictate the
need for transmission facilities. The TPL standards require extensive studies of the transmission system be performed
under steady state and dynamic conditions to understand and identify sensitive areas of the transmission system and
enable Reliability Coordinators to identify flowgates and other operating sensitivities in their respective regions. In light of
the Reliability Coordinators awareness of transmission sensitivities through these studies, it seems unnecessary to dictate
to the Reliability Coordinators additional criteria as proposed here in this Appendix B.
Individual
Jonathan Appelbaum
United Illuminating
Yes
We agree with the approach. We are concerned that the periodicity of the determination of the lines between 100 kV and
200 kV is not specified in Attachment B number 6 or R5. Is this an annual determination or performed only when a study
for the Planning Horizon is completed. Is the study period the short term planning horizon (1-5 year) or long-term planning
horizon (6-10 year)? For a temporary maintenance condition, e.g. a line is removed from service for 14 months, is the PC
required to reevaluate the list of facilities?
Individual
Ted Risher
Ingleside Cogeneration, LP
No
In paragraph 97 of Order 733, FERC allows for entities to challenge the identification of sub-200 kV transmission facilities
as critical to the BES. The paragraph reads as follows: “Finally, commenters argue that there should be some mechanism
for entities to challenge criticality determinations. We agree that such a mechanism is appropriate and direct the ERO to
develop an appeals process (or point to a process in its existing procedures) and submit it to the Commission no later than
one year after the date of this Final Rule.” Most of the proposed criteria leverage well-understood concepts such as
violations of IROLs or double contingencies. However, the proposed attachment includes a catchall statement under
Criterion #5 that the RC, PC, and RE can designate circuits as critical without any defined basis. This makes an appeals
process imperative since there are economic impacts to facility owners of such designations. This process needs to be
proposed and evaluated by the industry concurrently with Appendix B, not at a future date.
Group
Northeast Power Coordinating Council
Guy Zito
No
Support conformance with PRC-003 for all circuits 100 kV and above and as long as a reasonable period of time is
allowed for proper implementation. However, some circuits could be prioritized based on their criticality to the system. The
methodology in Attachment B should be considered as determining those circuits which should be prioritized first, followed
by the remaining circuits 100 kV and above. Further clarification is needed for Criterion #2 because the circuits which

make up an IROL can change depending upon the state of the system, while evaluation of relay loadability must be done
in advance. The following language is proposed: “Each circuit that is a monitored element of an IROL, assuming that all
transmission elements are in service and the system is under normal conditions.” Criterion #3 is unclear. The term “directly
related to” (off-site power supply to nuclear plants”) is so broad that it essentially covers all transmission circuits that are
connected to a nuclear plant. If this criterion meant to be the circuits that are directly connected to a nuclear plant, and
which form a critical path to supply backup power to the plant, then the criterion should be clarified. For example, some
plants may have low voltage (4160 V) cross-connects or distribution voltage (13.8 kV) circuits that provide off-site or
qualified alternate AC power supplies to nuclear plants which are likely not going to be subject to relay loadability
concerns due to transmission events (or such circuits may simply be providing power to office buildings). As written, it
could be interpreted that such circuits may have to be considered as part of this requirement. This is unnecessary. This
criterion needs to be revised such that lower voltage circuits which cannot be subjected to relay loadability concerns are
explicitly excluded, and also to limit its applicability to circuits that provide critical off-site power to nuclear plants as
identified in the Nuclear Plant Interface Requirements (NPIRs) provided by the Nuclear Plant Generator Operators to the
applicable Transmission Entities in accordance with NUC-001-2. Criterion #4 does not belong in this standard, and should
be eliminated. If the outage of an element causes unacceptable voltages elsewhere, appropriate actions should be taken
to address and remediate this issue. Conformance with PRC-023 is not going to solve the undesired consequences of an
outage, which could occur any time. NUC-001-2 already requires that the Nuclear Plant Generator Operator and the
applicable Transmission Entities: • coordinate on the testing, calibration and maintenance of on-site and off-site power
supply systems and related components (R9.3.3) • incorporate the NPIRs into their planning analyses of the electric
system (R3) • incorporate the NPIRs into their operating analyses of the electric system (R4.1) • operate the electric
system to meet the NPIRs (R4.2). Criterion #6 should be deleted. The PC and TP assess their future systems according to
the performance requirements stipulated in the TPL standards, including those in TPL-003. To require an entity to assess
the impact of a contingency that is not required by TPL-003 would go beyond the basic planning and design requirements.
Further, it raises the question on why do we single out the 100-200 kV facilities, but not all 200kV and above facilities?
Requirement R1 in the recent draft PRC-023 already asks for setting transmission line relays so they do not operate at or
below 115% of the highest seasonal 15-minute Facility Rating. This requirement is applicable for conditions with and
without faults on the system, and is sufficient to cover the testing condition stipulated in the proposed Criterion #6. The
system is neither planned nor operated to allow for two overlapping outages without operator action in between. If this
criterion is retained, it should be made consistent with the requirements of TPL-003, where operator actions can be
assumed between the first and second contingencies.
Group
PacifiCorp
Sandra Shaffer
Yes
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
No
The comment group agrees with all the criteria but number 6. Consider a local loop above 100 kV that is fed from a single
radial tap from the BES. Some regions continue to treat such radially fed systems as BES due to the presence of normally
open tie switches on the distribution system. It is conceivable that a multiple contingency within the loop could cause one
or more of the remaining un-faulted lines within the loop to overload to beyond 115% of their short term ratings. While
undesirable, such a scenario does not rise to the level of a BES event. Even if the lines cannot overload, entities will be
required to run simulations to prove non-applicability where such systems should be excluded by simple inspection. The
comment group suggests that radially operated (operated is the key word here) systems be excluded.
Individual
Kathleen Goodman
ISO New England Inc.
No
General comment: ISO New England supports conformance with PRC-003 for all circuits 100 kV and above allowing for a
reasonable period of time for proper implementation. However, some circuits could be prioritized based on their criticality
to the system. The methodology in Attachment B should be considered as determining those circuits which should be
prioritized first, followed by the remaining circuits 100 kV and above. Comments regarding specific criteria: 2. Further
clarification is needed regarding criterion #2, since the circuits which make up an IROL can change depending upon the
state of the system while evaluation of relay loadability must be done in advance. We proposed the following language:
“Each circuit that is a monitored element of an IROL, assuming that all transmission elements are in service and the
system is under normal conditions.” 3. The breadth of criterion #3 is unclear and may, as written, be broader than
necessary or appropriate. For example, some plants may have low voltage (4160 V) cross-connects or distribution voltage
(13.8 kV) circuits that provide off-site or qualified alternate AC power supplies to nuclear plants which are likely not going
to be subject to relay loadability concerns due to transmission events (or such circuits may simply be providing power to
office buildings). As written, it could be interpreted that such circuits may have to be considered as part of this
requirement, and we believe this to be unnecessary. This criterion needs to be modified such that lower voltage circuits
which cannot be subjected to relay loadability concerns are explicitly excluded and also to limit its applicability to circuits
that provide critical off-site power to nuclear plants, as identified in the Nuclear Plant Interface Requirements (NPIRs)
provided by the Nuclear Plant Generator Operators to the applicable Transmission Entities in accordance with NUC-001-2.
4. Criterion #4 should be eliminated. NUC-001-2 already requires that the Nuclear Plant Generator Operator and the
applicable Transmission Entities: • coordinate on the testing, calibration and maintenance of on-site and off-site power
supply systems and related components (R9.3.3) • incorporate the NPIRs into their planning analyses of the electric
system (R3) • incorporate the NPIRs into their operating analyses of the electric system (R4.1) • operate the electric

system to meet the NPIRs (R4.2). 6. Criterion #6 is overly stringent and should be deleted. The system is neither planned
nor operated to allow for two overlapping outages without operator action in between. If this criterion is retained, it should
be made consistent with the requirements of TPL-003, where operator actions can be assumed between the first and
second contingencies.
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
No
In general, Midwest Reliability Organization’s NERC Standards Review Subcommittee (NSRS) agrees with the proposed
criteria. However, there should be further clarification and qualification of the criteria noted below. In the introduction, the
wording of “determine if that circuit needs to be evaluated for conformance with PRC-023” does not clearly tie to
Requirement R5.1 or use the same language. We suggest revised wording to more clearly refer to Requirement R5.1 by
using the more similar language of, ”determine the circuits that are critical to the reliability of the BES”. For Criteria #4, add
the qualification that the outage condition is assessed for the near term planning horizon (years 1 to 5), rather imply that
the criteria includes consideration of the less certain longer term planning horizon (years 6 to 10). We suggest adding the
words, “for the near term planning horizon”, to the end of criteria #4. For Criteria #6, clearly limit the types of double
contingencies that should be considered to those identified in TPL-003 (e.g. more severe Category B), rather than imply
any and all double contingencies beyond TPL-003. In addition, there is no bound on all the N-1-1 contingencies that must
be considered (in TPL-003, the planner is allow to at least restrict the scope of study to the more severe contingencies.
We suggest revising the wording to, “. . . as a result of double contingencies that are required in the TPL-003 standard and
in addition, the more severe contingencies of loss of a single circuit, followed by the loss of a second circuit, without
system adjustments in between”. We do not believe that a flowgate should be automatically included in the criteria. The
NERC Glossary of Terms definition of flowgate would require every flowgate in the IDC to be identified. This is a problem
because flowgates are included in the IDC for many reasons not just because reliability issues are identified. Flowgates
could be included to simply study the impact of schedules on a particular interface as an example. It does not mean the
interface is critical. Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. Criterion 1 would imply that any monitored facility then
becomes subject to the standard. Furthermore, IDC is more of a congestion management tool than a reliability tool. FERC
recognized this in Order 693, when they directed NERC to make clear in IRO-006 that the IDC should not be relied upon
to relieve IROLs that have been violated. Rather, other actions such as redispatch must be used in conjunction. Thus, it
would appear that inclusion of a flowgate in the IDC does not indicate that it is critical. For Criteria #5, we suggest that the
applicable entities be changed. The Transmission Planner should be added because they have local planning
responsibilities and knowledge that should be factored into the consideration of critical circuit classification. We suggest
that the Regional Entity be removed because it does not fall within the Reliability Assurer functional tasks.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Yes
Individual
Kasia Mihalchuk
Manitoba Hydro
No
1) For criteria #5, Regional Entity does not need to be involved in determining the operational significant circuits. It should
be changed to: “Each circuit determined and agreed to by the Reliability Coordinator and the Planning Coordinator.” 2) For
criteria #6, it should be clarified that it would be up to the Planning Coordinator to make the engineering judgment in
determining the double contingencies beyond the requirements of TPL-003 standard. In addition, there should be some
coordination between the methodology for critical asset determination in the cyber security standards and the relay
loadability standard so multiple assessments are not required by the Planning Coordinator. Ideally, the scope of the TPL
assessment should provide sufficient information for the other relevant NERC standards.
Group
East Kentucky Power Cooperative, Inc.
Rick Drury
No
East Kentucky Power Cooperative (EKPC) agrees in principle with the establishment of criteria to be used to identify
circuits to be evaluated for conformance with PRC-023-2. However, EKPC does not believe that all of the proposed criteria
are appropriate. For instance, the first listed criterion that specifies any circuit listed as the monitored element of a flowgate
appears to be excessive. EKPC does not believe that flowgates necessarily correspond with a critical facility requiring
further analysis of relay settings. EKPC also does not agree with the 6th listed criterion as stated. We propose that the
criterion be modified to allow system adjustments between contingencies in accordance with the TPL-003 standard. EKPC
feels that this criterion stated in Attachment B should maintain consistency with the requirements for system performance
stated in TPL-003. With the elimination of the first criterion listed in Attachment B and the modification of the 6th listed
criterion to allow system adjustments between contingencies, EKPC would support the method listed in Attachment B for
identification of critical circuits.
Individual
Bill Miller
ComEd

Yes
Criteria number 6 calls for a test that includes comparison to the “Short Term Emergency Rating”. We have had some
confusion on exactly which rating this refers to. Thus, our comment is to add some clarifications to this term. For example
if this is the rating that is closest to a 15 minute highest seasonal facility rating, state this directly or in a footnote.
Group
Southern Company
Andy Tillery
Yes
For clarity, it is suggested that the two sentences above the criteria list of Attachment B be revised as follows: Review
each (line and transformer) circuit less than 200 kV against the following criteria to determine if that circuit must conform
with PRC-023. If any of the criteria below apply to the circuit under review, the circuit must conform to the requirements of
PRC-023.
Group
SERC Planning Standards Subcommittee
Philip R. Kleckey
No
Although this question states Attachment B contains the critical facilities test, it instead appears to contain a listing of
facilities to evaluate to determine if they are critical, and not the test itself. Attachment B states that if any of the criteria
apply to a circuit, the circuit needs to be evaluated. It should state that the circuit should be considered critical. Item1
should be removed since not all flowgates are related to reliability. The remaining items adequately cover lines less than
200 kV that are critical to reliability. Item 3 contains a typo. Change "are" to "is." Item 3: The word "related" is too vague,
recommend to use the word "connected" instead. Item 6 is confusing and should be revised as follows: "Each circuit
operated between 100 kV and 200 kV that exceeds its Short Term Emergency Rating by 15 percent or more as a result of
double contingency combinations selected by engineering judgment in TPL-003 Category C3, but without system
adjustments in between." The comments expressed herein represent a consensus of the views of the above-named
members of the SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.
Group
Pepco Holdings, Inc. - Affiliates
Richard Kafka
No
Mitigation timeframes are identified on the unofficial comment form, which differ from those defined by the implementation
plan in the most recent draft version of the standard. To be enforceable all mitigation timeframes need to be identified in
the standard itself. Secondly, the mitigation timeframes in the comment form use phrases like “by the time the overload
problem would be expected” and “before the operating time being analyzed”. The timeframe requirements for mitigation
need to be better defined to be auditable. The Planning Coordinator needs to determine an “exact date” when the
mitigation is required prior to the overload taking place. If that date is more than 24 months away then the protection
system owner will have to mitigate the facility before the required date established by the Planning Coordinator. However,
if the projected overload date is less than 24 months away, the protection system owner will have 24 months after being
notified by the Planning Coordinator to mitigate the facility; and operators shall be made aware of the loadability limitation
and should operate the facility accordingly until the facility is mitigated. The issue is that it may take 24 months for the
protection system owner to make necessary hardware upgrades to mitigate the loadability limitation.
Individual
Terry Harbour
MidAmerican Energy
No
The proposed criteria is not technically sound as many of the criteria are completely arbitrary and have no technical basis.
The appropriate basis for a critical element is something that could result in instability, uncontrolled separation, or
cascading which is the basis for all NERC standards, the 2003 blackout, and the Energy Policy Act wording. The following
proposed criteria is not technically sound and should be deleted: 1. Being a flowgate or monitored element of a flowgate.
The loss of a flowgate that doesn’t result in the instability, uncontrolled separation or cascading, may pose no more
jeopardy to grid reliability than any other element that isn’t designated as a flowgate. This was proved by FERC’s own
TIER report. 2. A circuit agreed to by the RC, PC, and RE. This has absolutely no technical basis whatever and is
completely arbitrary. This requirement also completely excludes the actual owner / operator of the facilities. 3. A circuit that
exceeds 15% of its short-term emergency rating as a result of a double contingency. This criteria exceeds what is required
in the TPL standards. For category C3 contingencies, the Planning Coordinator is allowed to assume operator intervention
between the first and second independent contingency. Further, this even exceeds what FERC ordered in their directive in
paragraph 79 from Order 733 which states: “To achieve this goal, the test to determine which sub-200 kV facilities are
subject to PRC-023-1 must include or be consistent with the system simulations and assessments that are required by the
TPL Reliability Standards and meet the system performance levels for all Category of Contingencies used in transmission
planning.” This proposed criterion is not consistent with the TPL standards but rather exceeds those standards. This
completely ignores any unusual or temporary operating conditions that could result from ice storms or even maintenance
practices.
Individual
Jerry Tang
MEAG Power
Yes

A minor clarification is needed. The first line under Criteria reads,"Review each circuit (line and transformer) less than 200
kV needs ..." It needs to be reworded as follows: "Review each circuit (line and low-side transformer) between 100 kV and
200 kV needs ..." The first line of number 6 needs to be reworded by deleting "between 100 kV and 200 kV." It would now
read, " EAch circuit operated that exceeds its Short Term ..."
Individual
JC Culberson
EROCT
No
In response to Attachment B of PRC-023, ERCOT ISO respectfully submits the following comments: Criterion 1 – the
phrase “Commercially Significant Constraint in the Texas Interconnection” and the associated footnote should be
removed. Commercially Significant Constraints (CSCs) are market-driven constraints designed to economically manage
congestion under the ERCOT Zonal market construct. CSCs are not reliability constraints that reflect the criticality of an
element relative to system reliability. Furthermore, as noted in footnote 1 in Attachment B, the ERCOT market is
transitioning from the current Zonal construct to a Nodal construct on December 1, 2010. Under the Nodal design CSCs
will not exist. Accordingly, the rules that apply to CSCs will expire prior to the implementation of this rule. Criterion 3 – The
word “are” should be replaced with the word “is”. Criterion 4 – There should not be any circuits whose outage causes
unacceptable voltages on the off-site power bus at a nuclear plant. Therefore, this criterion should be removed. Criterion 6
- Short Term Emergency Rating is not a defined term. Accordingly, it is not clear what rating is at issue. Emergency Rating
is a defined term, and ERCOT assumes that is the rating envisioned by this criticality identifier. If that is the case, it needs
to be clarified. If some other rating is envisioned, that too needs to be clarified, because, as noted, Short Term Emergency
Rating is not defined.
Group
System Protection Department
Bill Middaugh
No
1. We think that criterion 1 should be changed as follows “... Texas Interconnection, or path in the Western Interconnection
that is listed as an Existing Path in the current year WECC Path Rating Catalog.” The current wording “rated path in the
Western Interconnection” is too general and could be interpreted to mean any element in the Western Interconnection that
has a thermal rating. 2. Change “are” in criterion 3 to “is.” 3. We think that criterion 5 is too vague, may be discriminatory,
is unnecessary, and should be removed. There is no basis listed for determining circuits in this criterion, the criterion may
be applied discriminatorily or differently even within the same interconnection, it potentially excludes the protection system
owner from having input in the process, and there is no redress for appeal by the owner. Protection system owners do not
want transmission elements to be removed from service due to loading and nothing precludes a protection system owner
from applying PRC-023 requirements to lower voltage lines. We also think that getting agreement between the three
required entities could be troublesome. If some form of criterion 5 is included in the Attachment B, then it needs to define a
technical basis for the request for inclusion, a procedure to initiate the request for inclusion, due process defined for
evaluation of the request, and inclusion of the protection system owner in the evaluation process and the agreement. It
seems that criterion 6 defeats the need for criterion 5. 4. We think that criterion 6 should be revised to read as “Each
transmission line operated between 100 kV and 200 kV that exceeds its highest seasonal 15-minute Facility Rating or
each transformer operated between 100 kV and 200 kV that exceeds its operator established emergency transformer
rating as a result of a double contingency…” The current wording would have no positive impact on BES reliability. First,
the existing term “Short Term Emergency Rating” is not defined and is not used in PRC-023. We are suggesting changing
the concept to terms that are used in the standard. Secondly, nothing in PRC-023 requires the protection system owner to
set the relays to operate at more than 115% of an emergency rating or a short term (15-minute) rating. An element loading
that qualifies under the drafting team's proposed criterion 6 would not have to be considered unless it exceeded the 115%
of the emergency or short term rating, which the protection system settings would not be required to permit per the
requirements of PRC-023. That is why we changed the criterion to indicate inclusion of the element for any loading that
exceeded the emergency or short term rating for the contingencies studied.
Individual
Thad Ness
American Electric Power
No
These AEP comments are provided in the context of the primary goal of this standard as specified under R5, "... to prevent
cascading ...". The fundamental concern behind these comments is that the implemented methodology should not
unnecessarily and erroneously classify facilities as “critical”, even for the limited purposes of this single standard. Such
labels should only be applied to facilities that are truly “critical” to the reliability of the Bulk Electric System, and thus, the
implemented methodology should only identify “critical” facilities. In addition, the implementation plan must allow for ample
time to mitigate the initial wave of “critical” facilities that would reasonably be expected to be significantly larger than the
incremental number of new “critical” facilities that will be identified on a routine basis going forward. Specific comments on
the posted criteria being proposed by NERC are outline below. (1) Flowgates in the Eastern Interconnection (and
Commercially Significant Constraints in the Texas Interconnection) are defined for various reasons and not just for
reliability purposes. Flowgates are defined for interface monitoring, congestion management, and other purposes
unrelated to reliability. Many of the flowgates reflect nominal normal and emergency ratings to limit loadings on these
facilities below their thermal capabilities, and not for the purpose of preventing cascading. As such, being part of a
flowgate definition alone should not be the basis for suspecting susceptibility to cascading, and thus, not a good reason for
having such facilities meet the requirements of this standard. Furthermore, flowgates are updated on a continuous, and
many times, temporary basis, and thus, not a practical basis for identifying facilities for the purposes of this standard.
Therefore, this criterion should not be used as a basis for defining “critical” facilities for the purposes of this standard. (2)
Since the identification of “critical” facilities is made by the Planning Coordinators in the planning horizon (to give the relay
owners ample time to address compliance with the requirements of this standard), then the IROL methodology that is

applicable to the planning horizon (as specified under FAC-010) must be used to identify such “critical” facilities. In the
case of PJM, IROL facilities in the planning horizon are those SOL facilities that have been identified as potentially
resulting in cascading outages. As such, system reinforcements are developed in the planning horizon to ensure that such
cascading conditions are mitigated and do not materialize in the eventual operating horizon. Consequently, PJM does not
define any IROL facilities in the planning horizon. Therefore, this criterion can not be used as a basis for defining “critical”
facilities in the planning horizon for the purposes of this standard. On the other hand, IROL facilities identified in the
operating horizon (as specified under FAC-011), would be appropriate to use to identify “critical” facilities for the purposes
of this standard. (3) On the surface, this appears to be a reasonable criterion. However, need to clarify what is meant by
“directly related”. If these are facilities that are identified under the NPIRs mandated under NUC-001, then their associated
relay loadability performance should be addressed under NUC-001. Moving this requirement from PRC-023 to NUC-001
will ensure that all requirements associated with nuclear plants are addressed together under the same standard (NUC001). (4) On the surface, this appears to be a reasonable criterion. However, when such voltage studies are conducted
and unacceptable voltage conditions are identified in the planning horizon, system reinforcements and other mitigating
actions are taken to ensure that such conditions do not occur in the operating horizon. Consequently, since no such
conditions will be allowed to remain, then no “critical” facilities should result from this criterion. On that basis, this criterion
should be eliminated. If the criterion is kept, then it should be moved under NUC-001 for the same reasons noted under
criterion 3. Also, the criterion needs to specify the starting point of the outage analysis that identifies the unacceptable
voltages. Furthermore, the outaged facility needs to be subject to heavy loadings to be considered for possible
designation as a “critical” facility. The outage of the facility for reasons unrelated to heavy loadings should not be a basis
for making that facility subject to the requirements of this standard. (5) This criterion is too open ended and should be
eliminated. As the auditing entity, the Reliability Entity should not be providing any input outside of the auditing process.
The Planning Coordinator has the flexibility to engage any other entities as it sees fit, and thus, there is no need to single
out the Reliability Coordinator under this criterion. Also, even if these entities were kept and others, such as the
Transmission Owners, were added, what would be the basis that these entities would use to identify these “critical”
facilities? Again, this criterion is too open ended, it does not add anything meaningful to the effort, and thus, it should be
eliminated. (6) On the surface, this appears to be a rational basis for identifying “critical” facilities since it utilizes cascading
simulations. However, it stops short of performing the N-1-1-1 simulations (declares all overloaded facilities after the N-1-1
simulations as “critical” rather than going the extra step of performing the N-1-1-1 simulations to determine if any additional
facilities become overloaded) that are needed to demonstrate susceptibility to cascading. Furthermore, an additional filter,
one that takes into consideration the amount of load that would be placed at risk by the N-1-1-1 cascading scenario, also
needs to be incorporated into this methodology. This can best be achieved by giving the TOs an opportunity to review the
preliminary results from their Planning Coordinator and to demonstrate to their Planning Coordinator as to the amount of
load that would be at risk through the cascading of the proposed “critical” facilities. If the TOs can successfully
demonstrate to their Planning Coordinator that for certain facilities the amount of load that would be at-risk (from the
cascading scenario) falls below a specified threshold level (to be determined by their Planning Coordinator), then those
facilities would be excluded from the final list of “critical” facilities. In the end, this should be the only criterion that is used
to identify “critical” facilities for the purposes of this standard. Regarding the use of Short Term Emergency Ratings in the
simulations, it should be noted that most ratings used in planning base cases (the ones that would be used by the
Planning Coordinator) are Long Term Emergency Ratings, and thus, converting such models to reflect Short Term
Emergency Ratings just for the purposes of conducting these simulations would not be practical. Therefore, the
specification should be made as a higher percentage of Long Term Emergency Ratings.
Group
FirstEnergy
Sam Ciccone
No
FirstEnergy has the following comments related to the proposed criterion presented in the Attachment B of PRC-023-2. A.
Consistency with the CIP-002-4 bright-line criteria. When comparing the proposed PRC-023-2 Attachment B criterion to
the bright-line criteria proposed for CIP-002-4 Attachment 1 Critical Asset determination there is a great deal of overlap in
concepts presented for transmission facilities. For example, each cover aspects of transmission facilities associated with
IROLs and transmission facilities that are operationally significant for the safe operation and shutdown of a nuclear
generation plant. Since these are parallel standard development efforts we suggest to the extent possible the PRC team
and CIP team use consistent language when equivalent technical concepts are utilized for critical facility determinations.
FirstEnergy's suggested changes identified below for the six individual criterion are consistent with CIP-002-4 Attachment
1 proposals made by FirstEnergy. B. Leverage existing studies and analysis - planning timeframe. We concur with the
drafting team’s perspective that tests for the applicability of PRC-023 should leverage as much existing work as possible,
however, FE believes any study/analysis work should be limited to that performed by the planning coordinators and
transmission planners and not the transmission operators as suggested by the comment form background information. FE
believes the appropriate timeframe to identify the sub 200kV critical facilities is the planning horizon based on forward
looking studies conducted by or under the supervision of the planning coordinator. This is consistent with PRC-023-1 (R3)
and the proposed PRC-023-2 (R5) since the planning coordinator is the applicable entity required to determine the sub
200kV critical facilities and the time-horizon for the requirement is long-term planning. Information based on analysis
performed by the reliability coordinator or transmission operator within the operating time horizon, such IROL, can be
temporary, dynamic and subject to change. Therefore, it should be clear that the intent of facilities associated with IROLs
are based on planning timeframe analysis. See FE's proposed changes to the second criterion. C. Mitigation Timeframes.
The comment form provided by the drafting team presented two criteria for mitigation timeframe. This information should
not be buried in a comment form but rather part or the standard's Effective Date's section (Section 5) and presented in an
Implementation Plan so that it may be fully vetted by industry through the standards development process. The mitigation
timeframe should be clear that the minimum expectation is 24-months upon the asset owner being notified by the planning
coordinator of a new critical facility determination. The first bulleted item presented by the team is vague if its meant to be
the "greater of" or "lesser of" 24 months or the time the overload problem would be expected. As stated above, FE
believes that critical facility determinations are appropriately based on planning horizon timeframes and therefore it should
be clear that an asset owner is afforded a minimum 24-month period to mitigate any critical facility required to meet PRC-

023. This is consistent with the approved version 1 and the proposed version 2 standard. D. Specific comments on the
Attachment B Criterion. i. Criteria 1: A flowgate should not be automatically included in the criteria. The NERC Glossary of
Terms definition of flowgate would require every flowgate in the IDC to be identified. This is a problem because flowgates
are included in the IDC for many reasons not just because reliability issues are identified. Flowgates are used for market
recognition to study the impact of schedules on a particular interface and may not present a reliability concern. The team
should consider a more limiting use of flowgate or striking the criteria. ii. Criteria 2: FE agrees with the concept of
associating a critical facility with IROL however we believe two important revisions are required. First, the critical facility
should be based on the contingent facilities that describe the IROL and not the monitored elements. Second, the IROL
determinations should be based on planning horizon studies. FirstEnergy proposes the following text for criteria 2:
"Transmission Facilities that the Planning Coordinator or Transmission Planner designates that, if destroyed, degraded,
misused or otherwise rendered unavailable, demonstrates the need for an Interconnection Reliability Operating Limit
(IROL)." iii. Criteria 3: FE supports criteria 3 and proposes revision so that criteria 3 reads “BES Facilities providing offsite
power requirements as identified in the Nuclear Plant Interface Requirements.” iv. Criteria 4: Criteria 4 should be removed
since criteria 3, as revised above, should adequately cover the transmission facilities deemed critical for a nuclear
generation facility as designated in their NPIRs. v. Criteria 5: Criteria 5 is vague, open ended and should be removed. Any
criteria that the PC may use to include other facilities should be explicitly stated in Attachment B. The RC should be
removed since it makes evaluations within the operating horizon timeframe which is not appropriate for requirement R5. vi.
Criteria 6: FE supports this criteria.
Group
Salt River Project
Cynthia Oder
No
There is an error in the wording under R5, this requirement states "transmission lines operated at below 200kV and
transformers below 230kV." It should state "transmission lines operated between 100kV and 200kV and transformers
operated between 100kV and 200kV" otherwise this standard will fall out of the definition of BES.
Individual
Randi Woodward
Minnesota Power
No
Minnesota Power recommends that the Standards Drafting Team consider changing item #6 to read as follows: Each
circuit operated between 100 kV and 200 kV that exceeds its Short Term Emergency Rating by 15 percent or more as a
result of a double contingency (for those combinations selected by engineering judgment in TPL-003 System Performance
Following Loss of Two or More BES Elements analyses).
Group
Operational Compliance
Cathy Koch
Yes
We would like to propose a rewrite for criterion #6. The proposed rewrite is: "Each circuit operated between 100 kV and
200 kV that exceeds its short term Emergency Rating by 15% or more as the result of a double contingency, beyond the
requirements of TPL-003 C3 (i.e. loss of a single circuit followed by the loss of a second circuit without manual system
adjustments in between), for all combinations selected by engineering judgment in the TPL-003 C3 analyses." Note - This
modified TPL-003 C3 contingency reflects a situation where a System Operator may not have time between two
contingencies to make appropriate system adjustments. The term “Short Term Emergency Rating” is not a defined term so
“short term” should not be capitalized and could potentially be removed. The definition of Emergency Rating specifies a
finite time period. The addition of the word 'manual' before 'system adjustment' mirrors the TPL-003 C3 definition and
better clarifies what is meant by 'system adjustment' as this is not a defined term. This would then imply that automatic
system adjustments that occur due to RAS and SPS operations, transformer tap changes and automatic switching of
reactive resources would not constitute a 'system adjustment' in the context of this criterion (further supported by the note
to criterion #6).
Individual
Dan Rochester
Independent Electricity System Operator
No
We agree with Criteria # 1, 2 and 5, but do not agree with Criteria #3, #4 and #6. Criterion #3 is unclear. The term “directly
related to” (off-site power supply to nuclear plants” is so broad that it essentially covers all transmission circuits that are
connected to a nuclear plant. If this criterion meant to be the circuits that are directly connected to a nuclear plant and
which form a critical path for supply backup power to the plant, then the criterion should say so to provide better clarity.
Criterion #4 does not belong in this standard. If the outage of an element causes unacceptable voltages elsewhere,
appropriate actions should be taken to address and remediate this issue. Conformance with PRC-023 is not going to solve
the undesired consequences of an outage, which could occur any time. Criterion #6 is troublesome and perhaps not
needed. The PC and TP assess their future systems according to the performance requirements stipulated in the TPL
standards, including those in TPL-003. To require an entity to assess the impact of a contingency that is not required by
TPL-003 would go beyond the basic planning and design requirements. Further, it raises the question on why do we single
out the 100-200 kV facilities, but not all 200kV and above facilities? Requirement R1 in the recent draft PRC-023 already
asks for setting transmission line relays so they do not operate at or below 115% of the highest seasonal 15-minute
Facility Rating. This requirement is applicable for conditions with and without faults on the system, and is sufficient to
cover the testing condition stipulated in the proposed Criterion #6. We suggest to remove this Criterion #6.
Individual

Kirit Shah
Ameren
No
Criterion #1 : A monitored flowgate does not imply a reliability issue. Flowgates are monitored for many reasons, some for
reliability and some to regulate the amount of firm transmission service. In non-FTR markets, firm transmission monitoring
may be a partial function of reliability. However, in FTR markets, the sale of firm transmission service may be related to
the acquisition of ARR/FTRs. Under these scenarios, the flowgate may be in place to ensure FTR funding sufficiency.
Circuits with high degrees of uncertain loading are most susceptible but the mere presence of uncertainty does not make
them critical for the reliability of the BES. Criterion #2: We are ok with the element related to “IROL” type criterion including
outage of such element causing instability or cascading effect on the BES. Criterion #3: We believe that our comment
should be restated as “This criterion should not be included in a relay loadability test. The fact that a circuit supplies a
reserve aux transformer at a nuclear plant does not make the circuit critical to the transmission network or to the plant. If
the outage of a circuit results in the outage or instability of a nuclear plant, then these issues should have been addressed
in the design of the plant supply and/or in the TPL-002 assessment.” Criterion 4: This issue should be covered in TPL-002
or NUC-001. This item should not be included in a relay loadability test. Criterion #5: This is an open-ended criterion
without any supporting basis. It is also unclear who at the Regional Entity would “sign-off”, Compliance, Engineering, or
someone else? Further, this type of criterion would introduce more inconsistencies rather uniformity. If such a criterion is
used, we suggest that the RC, PC, and/or RE should work closely with the local Transmission Planners to determine if a
circuit should be assessed for criticality and further subjected to the relay loadability test. Criterion #6: Short Term
Emergency Rating, although capitalized in here, is not a NERC defined term. Further, the criterion does not identify the
time duration that the STE rating would be applicable, nor the basis for such a rating. If a common time duration and basis
for rating could be established, a common loading above the STE rating could be established. A loading of 120% may be
more indicative of a cascade than 115%, and would be applicable for fast acting contingencies involving multiple circuits,
including Category C1 bus faults, C2 breaker failures, or C5 double-circuit tower outages. We do not agree with the
proposal that system adjustments would not be allowed for slower multiple contingency Category C3 events (sometimes
referred to as N-1-1 outages) involving lines, generators or transformers, as this requirements clearly steps on standard
TPL-003.
Group
Midwest ISO Standards Collaborators
Jason L. Marshall
No
We have many concerns with the approach identified. We do not believe that a flowgate should be automatically included
in the criteria. The NERC Glossary of Terms definition of flowgate would require every flowgate in the IDC to be identified.
This is a problem because flowgates are included in the IDC for many reasons not just because reliability issues are
identified. Flowgates could be included to simply study the impact of schedules on a particular interface as an example. It
does not mean the interface is critical. Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC
flowgates is updated monthly and IDC users can add temporary flowgates at anytime. Criterion 1 would imply that any
monitored facility then becomes subject to the standard. Furthermore, the IDC is more of a congestion management tool
than a reliability tool. FERC recognized this in Order 693, when they directed NERC to make clear in IRO-006 that the IDC
should not be relied upon to relieve IROLs that have been violated. Rather, other actions such as redispatch must be used
in conjunction. Thus, it would appear that inclusion of a flowgate in the IDC does not indicate that it is critical. For criterion
2, we believe any contingent facility or prior outage that sets up the IROL should be included if criterion 6 is revised to
allow operator intervention between contingencies. If criterion 6 is not revised, we do not support adding contingency or
prior outages. For criterion 3, what does it mean to be directly related to the off-site supply to nuclear plants? Does this
means it is identified in the NPIRs associated with the agreements mandated by NUC-001-2? This criteria needs to be
further refined if retained. For criterion 4, since NERC standards collectively require us to operate the system to N-1 and to
plan the system with Category C contingencies, this criterion should never identify any facilities with low voltage. For
criterion 5, this criterion is too open ended and should be eliminated. Since the Regional Entity is the auditor, they should
not provide direct input into what is included. This seems like carte blanche for the Regional Entity to add to the list of
facilities whenever the latest issue arises. Could we end up having a situation where after every event analysis the
Regional Entity identifies even more facilities? If the Regional Entities have needs to identify facilities they should do this
by providing input through the standards development process to suggest modifications to the criteria. Will the RC and PC
be judged similar to how entities are currently being judged regarding the number of Critical Assets that have been
identified for CIP? If so, this could become a “bring me a rock” exercise. If the PC and RC don’t identify enough facilities,
will the ERO and Regional Entities pressure them to identify more? Industry will be better served if we eliminate this open
ended criteria and just identify bright line criteria for what should be included. This really seems like a catch all in case we
forget to add all the necessary criteria. For criterion 6, we disagree with this criterion because it exceeds what is required
in the TPL standards. For category C3 contingencies, the Planning Coordinator is allowed to assume operator intervention
between the first and second independent contingency. Further, this even exceeds what FERC ordered in their directive in
paragraph 79 from Order 733 which states: “To achieve this goal, the test to determine which sub-200 kV facilities are
subject to PRC-023-1 must include or be consistent with the system simulations and assessments that are required by the
TPL Reliability Standards and meet the system performance levels for all Category of Contingencies used in transmission
planning.” This proposed criterion is not consistent with the TPL standards but rather exceeds those standards.
Individual
Steve Rueckert
WECC
No
The approach described is reasonable, however, it would be more comprehensive and consistent to replace in item 1
(Attachment B), "rated path in the Western Interconnection" with "paths included in Table of Major WECC Transfer Paths
in the Bulk Electric System". This Table is more comprehensive because it is identified by the WECC Operating

Committee and is consistent with the major paths used in other WECC Standards. Item 5 appears vague. What does
“agreed to by the Reliability Coordinator, the Planning Coordinator, and Regional Entity mean?” Do all three need to be in
agreement before a facility is to be added to the list to be evaluated, or can any one of them add it to the list? How are
these entities supposed to come to agreement and document that agreement. If there is not a proactive effort to develop
the list and “agree” to it, there probably won’t be a list. I’m not sure I understand Item 6. Does this mean that results of
TPL-003 assessments will helpt identify circuits that have to be evaluated? TPL-003 is eventually going to go away when
the ATFNSDT effort is completed. The requirement to conduct the types of assessments currently included in TPL-003 will
not go away, but the specific referenct to TPL-003 could become obsolete.
Individual
Chifong Thomas
Pacific Gas and Electric Company
No
We believe the approach described is reasonable, however, as written Item 1 (Attachment B) concerning WECC paths is
vague. We suggest, replacing "rated path in the Western Interconnection" with "paths included in Table of Major WECC
Transfer Paths in the Bulk Electric System". We believe referencing this Table would provide clarity because the paths in
this Table are identified by the Operating Committee in WECC and are consistent with the major paths used in other
WECC Standards, such as FAC-501-WECC-1, PRC-004-WECC-1, and TOP-007-WECC-1.
Group
Dominion
Louis Slade, Jr.
No
While items 1-5 seem reasonable, Dominion takes exception with item six (6). Item six goes beyond TPL-003 criteria, by
assuming the operator will have no time between contingency events to make system adjustments. TPL-003 was
thoroughly vetted when it was developed and is sound criteria that has been in place for years. Circuits below 200 kV are
less critical to the security of the bulk electric system. We see no reason why the standard should not allow that the
operator will make system adjustments between the first and second contingency.
Individual
Stephen R. Stafford
Georgia Transmission Corporation
No
Criterion 6 of Attachment B states "Each circuit operated between 100 kV and 200 kV that exceeds its Short Term
Emergency Rating by 15 percent or more as a result of a double contingency..." The basis for the 15 percent criterion has
not been clearly explained. What is the basis for this criterion? Based on this criterion, multiple lines could be identified as
critical facilities, when, in fact, loss of these lines could have no significant impact to the BES(i.e. not cause cascading
outages on the BES).
Individual
Greg Rowland
Duke Energy
No
• General Comment – It should be made clear that the application of these criteria is intended to determine which facilities
must be evaluated for applicability of PRC-023-2 and may not necessarily dictate modification of relay settings. Situations
where there is time for operator intervention, or no cascading, wouldn’t need loadability protection. • Criteria 1 – We do not
believe that flowgates should be automatically included as a criteria, since a flowgate may be in the IDC for business
reasons. Also, the list of flowgates is dynamic. • Criteria 2 – Monitored elements of an IROL are also dynamic and we
question how you could apply this in the planning timeframe so it could be used to set relays. IROLs identified in the
planning horizon should be mitigated by some action prior to reaching the operating horizon. This criteria is not specific
enough to be applied consistently. • Criteria 3 – What is meant by “directly related”? There is a difference between normal
off-site power and emergency power. We don’t think the NPIRs would clarify this situation. Is the expectation that no lines
connected to a nuclear plant trip except for a fault on the line? • Criteria 4 – If we had such a circuit it would violate TPL002 as well as the NPIRs, so this is not a useful criteria, because you’ll never identify anything with it. • Criteria 5 – It
doesn’t make sense to include the Regional Entity, because the Regional Entity doesn’t do the analysis. Also, this criteria
just says you can go beyond the existing criteria, which is always an option – so why include it as a criteria? • Criteria 6 –
“Short Term Emergency Rating” is not a defined term. However its use in conjunction with the 15% overload suggests that
a 15-minute Emergency Rating is what is intended. Some Transmission Owners haven’t determined sufficiently short term
Emergency Ratings to meet the intent of this criteria, and if they set their relays at 115% of their shortest term Emergency
Rating they would restrict loadability more than the standard should allow. Regardless of how the criteria for contingency
line loading are defined in Attachment B, the criteria should match the requirements of PRC-023-2.
Individual
Armin Klusman
CenterPoint Energy
No
Considering situations where the transmission system may be at risk of cascading outages or voltage collapse,
CenterPoint Energy believes sub-200 kV elements should be considered operationally significant only whenever
reasonably contemplated scenarios would cause high amperage and low voltage to be experienced on the elements.
Criteria 6 that proposes loading greater than 15% of the short term emergency rating following a double contingency is not
a technically sound method to indicate if an element is operationally significant. CenterPoint Energy recommends only
criteria 1 through 5 be used to determine whether a sub-200 kV element is operationally significant to the reliability of the

bulk power system.
Group
Bonneville Power Administration
Denise Koehn
No
BPA would like to raise the concern regarding the terminology being used in PRC-023. An underlying principle of the
standard is to "Determine which of the facilities in its Planning Coordinator Area are critical to the reliability of the BES…".
BPA would like to take this opportunity to point out that determination of “critical” as PRC-023 is applied may not be
directly reflective of CIP Critical Asset identification. BPA feels this is appropriate due to the guidance provided in CIP-002
R1 where the Risk-Based Assessment Methodology should include the following considerations (as we used to develop
BPA's methodology): 1) Control centers and backup control centers; 2) Transmission substations that support the reliable
operation of the Bulk Electric System; 3) Generation resources that support the reliable operation of the Bulk Electric
System; 4) Systems and facilities critical to system restoration, including blackstart generators and substations in the
electrical path of transmission lines used for initial system restoration; 5) Systems and facilities critical to automatic load
shedding under a common control system capable of shedding 300 MW or more; 6) Special Protection Systems that
support the reliable operation of the Bulk Electric System; and 7) Any additional assets that support the reliable operation
of the Bulk Electric System that the Responsible Entity deems appropriate to include in its assessment. No minimum kV
levels are instructed to be specifically used to identify CIP Critical Assets where PRC-023 is heavily driven by kV levels.
BPA believes it would be very labor intensive to try and come up with which circuits would exceed the STE rating by 15%
or more. BPA would like to understand the benefit of this study to increasing reliability. For Attachment B, BPA believes
the performance requirement needs to be clarified further. The term "double contingency" and reference to "TPL-003"
needs to be more specific, since TPL does cover more than just N-2 contingency of circuit elements. Additionally,
regarding the Standard itself, for some local areas, if three lines are feeding the local area and it has been planned per the
Standards (e.g. one single 115 kV line can't feed 100% of load in the area for loss of the other two), it seems like if two of
the lines are lost simultaneously, then loss of the third line quickly, rather than waiting for an operator response may be
preferable. This could be a safety issue and the operator may have no control over outcome. Additional comments: BPA
would find it helpful if the drafting team were to create a cross-walk of the FERC directives (as listed on Page 3 and 4 of
the SAR) and how/where the drafting team is addressing them.
Individual
Charles Lawrence
American Transmission Company
No
In general, we agree with the proposed criteria. However, we propose the following changes to the introduction, Criteria #4
and Criteria #6. [[1]]- In the introduction, the wording of “determine if that circuit needs to be evaluated for conformance
with PRC-023” does not clearly refer to Requirement R5.1 or use the same language as R5.1. We believe that the wording
in Attachment B should match the wording in R5.1. However, use of the terminology, “critical to reliability of the BES”,
keeps causing confusion with the meaning of the concept of “critical” as it is defined in the CIP-002 standard. Therefore,
we propose replacing the “critical” terminology in R5.1 with distinctly different terminology like, “that have major operational
significance to the reliability of the BES”. Then, use wording similar to R5.1 in Attachment B such as, “determine the
circuits that have major operational significance to the reliability of the BES”. [[2]]- For Criteria #4, add the qualification that
the outage condition is assessed for the near term planning horizon (years 1 to 5), rather imply that the criteria includes
consideration of the less certain longer term planning horizon (years 6 to 10). We suggest adding the words, “for the near
term planning horizon”, to the end of criteria #4. [[3]]- For Criteria #6, clearly limit the types of double contingencies that
should be considered to those identified in TPL-003 (e.g. more severe Category B), rather than imply any and all double
contingencies beyond TPL-003. In addition, there is no bound on all the N-1-1 contingencies that must be considered (in
TPL-003, the planner is allow to at least restrict the scope of study to the more severe contingencies. We suggest revising
the wording to, “. . . as a result of double contingencies that are required in the TPL-003 standard and in addition, the
more severe contingencies of loss of a single circuit, followed by the loss of a second circuit, without system adjustments
in between”.
Individual
Alice Murdock Ireland
Xcel Energy
No
Item 1 – it is not clear how ‘temporary flowgates’ would be considered I this application; “commercial” considerations
should not be part of a reliability standard; “rated path” in WECC is not clear – are these any path in the WECC Path
Catalog, or is it intended to mean the “Major WECC Paths…”? Item 4 - we feel it should be eliminated from the list of
criteria. Since NERC standards collectively require us to operate the system to N-1 and to plan the system with Category
C contingencies, this criterion should never identify any facilities with low voltage. Item 5 – this appears to give carte
blanche authority to the PC/RC/RE to decide a circuit is subject to evaluation; we believe this should be tempered with
concurrence from the TO/GO/DP.
Group
IRC Standards Review Committee
Ben Li
No
Criterion 1 is inappropriate and should be eliminated. It states that any monitored facility below 200KV would be subject to
this standard. A facility that is designated as a flowgate should NOT be automatically assumed to have an impact on
reliability. Flowgates are included in the IDC for many reasons and not always because the facilities are critical to bulk
system reliability. Some flowgates are defined and included in the IDC only to have the PTDF, OTDF and LODF

calculated. In general, flowgates are not a good indicator for reliability needs; the master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. Furthermore, IDC is primarily used to study congestion
and is the basis of Transmission Loading Relief (TLR) which is not a reliability tool. FERC recognized this in Order 693,
when they directed NERC to make clear in IRO-006 that the IDC should NOT be relied upon to relieve IROLs that have
been violated and other actions such as redispatch must be used in conjunction with TLR. Criterion 2 should state that any
contingent facility or prior outage that sets up the IROL be included, except where such facility is used as a proxy for
assessing the IROL. Criterion 3 is unclear and should be clarified. What does it mean to be “directly related” to the off-site
supply to nuclear plants? More clarity in the wording is needed. Is the intent that facilities that provide off-site power to
nuclear plants as defined in the NPIRs associated with the agreements mandated by NUC-001-2 are captured in this
standard? Criterion 4 is not needed since NERC standards already contain requirements to operate the system to N-1 and
to plan the system with Category C contingencies. Therefore, this criterion would never identify any facilities whose outage
would cause low voltage. Criterion 5 is too open ended and should be eliminated. The Regional Entity serves primarily as
the compliance enforcement authority and not the technical assessor of what facilities are critical for bulk power reliability.
They do not perform any of the operating and planning functions required to comply with reliability standards. These
criteria should strive to be as close as possible to “bright line” tests. Criterion 5 is in a sense rhetorical, like defining a word
with the same word. Criterion #6 should be deleted. This criterion does not recognize that the system is neither planned
nor operated to allow for two overlapping outages without operator action in between. This goes beyond the assessment
and performance requirements of TPL-003, where operator actions can be assumed between the first and second
contingencies. We also ask why a 15% over Short Term Emergency Rating is an appropriate level, there is no justification.

Consideration of Comments on Relay Loadability Order — Project 2010-13
The Relay Loadability Order Drafting Team thanks all commenters who submitted comments
on the proposed applicability test contained in Attachment B to PRC-023-2. These
standards were posted for a 20-day abbreviated public comment period from September 23,
2010 through October 12, 2010. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 39 sets of comments,
including comments from more than 117 different people from approximately 95 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.

http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition,
there is a NERC Reliability Standards Appeals Process. 1

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

Consideration of Comments on Relay Loadability Order — Project 2010-13

Index to Questions, Comments, and Responses
1.

Attachment B is intended to contain the test that the Planning Coordinators must use to
determine whether a sub-200kV facility is critical to the reliability of the bulk power system.
Do you agree that the method proposed in Attachment B is a technically sound approach to
determine whether a sub-200kV facility is critical to the reliability of the bulk power system?
…. ................................................................................................................... 10

Consideration of Comments on Relay Loadability Order — Project 2010-13
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

Guy Zito

Northeast Power Coordinating Council

Additional Member Additional Organization

Region

Segment
Selection

Alan Adamson

New York State Reliability Council, LLC

NPCC

Gregory Campoli

New York Independent System Operator

NPCC

Kurtis Chong

Independent Electricity System Operator

NPCC

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

Dean Ellis

Dynegy Generation

NPCC

Brian Evans-Mongeon

Utility Services

NPCC

Mike Garton

Dominion Resources Services, Inc.

NPCC

10.

Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

11.

Kathleen Goodman

ISO - New England

NPCC

12.

Chantel Haswell

FPL Group, Inc.

NPCC

13.

David Kiguel

Hydro One Networks Inc.

NPCC

Consideration of Comments on Relay Loadability Order — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

14.

Michael R. Lombardi

Northeast Utilities

NPCC

15.

Randy MacDonald

New Brunswick System Operator

NPCC

16.

Bruce Metruck

New York Power Authority

NPCC

17.

Lee Pedowicz

Northeast Power Coordinating Council

NPCC

18.

Robert Pellegrini

The United Illuminating Company

NPCC

19.

Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC

20.

Saurabh Saksena

National Grid

NPCC

21.

Michael Schiavone

National Grid

NPCC

22.

Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC

Group
Additional Member

Steve Alexanderson

Pacific Northwest Small Public Power Utility
Comment Group

Additional Organization

Region Segment Selection

1. Ronald Sporseen

Blachly-Lane Electric Cooperative

2. Ronald Sporseen

Central Electric Cooperative

3. Ronald Sporseen

Consumers Power

4. Ronald Sporseen

Clearwater Power Company

5. Ronald Sporseen

Douglas Electric Cooperative

6. Ronald Sporseen

Fall River Rural Electric Cooperative

7. Ronald Sporseen

Northern Lights

8. Ronald Sporseen

Lane Electric Cooperative

9. Ronald Sporseen

Lincoln Electric Cooperative

10. Ronald Sporseen

Raft River Rural Electric Cooperative

11. Ronald Sporseen

Lost River Electric Cooperative

12. Ronald Sporseen

Salmon River Electric Cooperative

13. Ronald Sporseen

Umatilla Electric Cooperative

14. Ronald Sporseen

Coos-Curry Electric Cooperative

15. Ronald Sporseen

West Oregon Electric Cooperative

16. Ronald Sporseen

Pacific Northwest Generating Cooperative

Consideration of Comments on Relay Loadability Order — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

17. Ronald Sporseen

Power Resources Cooperative

18. Russell A. Noble

Cowlitz County PUD No. 1

3, 4, 5

19. Dave Proebstel

Clallam County PUD

Group

Region

Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

Chuck Lawrence

American Transmission Company

MRO

Tom Webb

WPS Corporation

MRO

3, 4, 5, 6

Jason Marshall

Midwest ISO Inc.

MRO

Jodi Jenson

Western Area Power Administration MRO

1, 6

Ken Goldsmith

Alliant Energy

MRO

Alice Murdock

Xcel Energy

MRO

1, 3, 5, 6

Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10.

Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

11.

Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

12.

Scott Nickels

Rochester Public Utilties

MRO

Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

Additional
Member

Additional
Organization

Segment
Selection

Philip R. Kleckey

Carol Gerou

Group

MRO's NERC Standards Review
Subcommittee

Additional Member Additional Organization

13.

SERC Planning Standards Subcommittee
Region

Segment
Selection

John Sullivan

Ameren Services Company

SERC

Charles Long

Entergy

SERC

James Manning

North Carolina Electric Membership
Corporation

SERC

Jim Kelley

PowerSouth Energy Cooperative

SERC

Consideration of Comments on Relay Loadability Order — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Bob Jones

Southern Company Services, Inc. - Trans.

SERC

Pat Huntley

SERC Reliability Corporation

SERC

Group

Richard Kafka

Additional Member

Pepco Holdings, Inc. - Affiliates

Additional Organization

Potomac Electric Power Company RFC

2. Walt Blackwell

Potomac Electric Power Company RFC

3. Carl Kinsley

Delmarva Power & Light Co.

RFC

4. Jason Parsick

Potomac Electric Power Company RFC

5. Evan Sage

Potomac Electric Power Company RFC

6. Rob Wharton

Atlantic City Electric

Bill Middaugh

Additional Member

RFC

System Protection Department

Additional Organization

Tri-State Generation and Transmission Ass'n., Inc. WECC 1, 3, 5

2. Gary Preslan

Tri-State Generation and Transmission Ass'n., Inc. WECC 1, 3, 5

3. Matthew Leyba

Tri-State Generation and Transmission Ass'n., Inc. WECC 1, 3, 5

4. LeRoy Martinez

Tri-State Generation and Transmission Ass'n., Inc. WECC 1, 3, 5

Group

Sam Ciccone

Region Segment Selection

1. Jim Pearsall

Region Segment Selection

1. Alvin Depew

Group

FirstEnergy

Additional Member Additional Organization Region Segment Selection
1. Rich Maxwell

RFC

2. Doug Hohlbaugh

RFC

3. Jeff Mackauer

RFC

Group

Jason L. Marshall

Midwest ISO Standards Collaborators

Additional Member Additional Organization

Region

Segment
Selection

Joe O'Brien

NIPSCO

RFC

Terry Harbour

MidAmerican

MRO

1, 3, 5, 6

Consideration of Comments on Relay Loadability Order — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Jim Cyrulewski

JDRJC Associates, LLC

RFC

Barb Kedrowski

We Energies

RFC

3, 4, 5

Bill Hutchison

Southern Illinois Power Cooperative SERC

Joe Knight

Great River Energy

MRO

1, 3, 5, 6

Kirit Shah

Ameren

SERC

Group

Louis Slade, Jr.

Dominion

Additional Member Additional Organization

Region

Mike Garton

Electric Mkt. Policy

RFC

5, 6

Michael Gildea

Electric Mkt. Policy

MRO

5, 6

Angela Park

Electric Tranmission SERC

1, 3

John Loftis

Electric Tranmission SERC

1, 3

10.

Group

Denise Koehn

Additional
Member

Additional
Organization

Segment
Selection

Bonneville Power Administration
Region

Segment
Selection

Lorissa Jones

BPA, Transmission Reliability Program

WECC

Dick Winters

BPA, Transmission Substation Operations

WECC

Curt Wilkins

BPA, Transmission Control Cntr HW Design &
Maint

WECC

Steve Larson

BPA Legal

WECC

Rita Coppernoll

BPA, Transmission SPC Technical Svcs

WECC

Dean Bender

BPA, Transmission SPC Technical Svcs

WECC

Chuck Matthews

BPA, Transmission Planning

WECC

Berhanu Tesema

BPA, Transmission Planning

WECC

11.

Individual

Sandra Shaffer

PacifiCorp

12.

Individual

Jana Van Ness

Arizona Public Service Company

Consideration of Comments on Relay Loadability Order — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

13.

Individual

Rick Drury

East Kentucky Power Cooperative, Inc.

14.

Individual

Andy Tillery

Southern Company

15.

Individual

Cynthia Oder

Salt River Project

16.

Individual

Cathy Koch

Operational Compliance

17.

Individual

Donna Jordan

California ISO

18.

Individual

Robin W. Blanton

Piedmont EMC

19.

Individual

Michael Gammon

Kansas City Power & Light

20.

Individual

Jonathan Appelbaum

United Illuminating

21.

Individual

Ted Risher

Ingleside Cogeneration, LP

22.

Individual

Kathleen Goodman

ISO New England Inc.

23.

Individual

Kasia Mihalchuk

Manitoba Hydro

24.

Individual

Bill Miller

ComEd

25.

Individual

Terry Harbour

MidAmerican Energy

26.

Individual

Jerry Tang

MEAG Power

27.

Individual

JC Culberson

EROCT

28.

Individual

Thad Ness

American Electric Power

X
X
X

X
X

Consideration of Comments on Relay Loadability Order — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

29.

Individual

Randi Woodward

Minnesota Power

30.

Individual

Dan Rochester

Independent Electricity System Operator

31.

Individual

Kirit Shah

Ameren

32.

Individual

Steve Rueckert

WECC

33.

Individual

Chifong Thomas

Pacific Gas and Electric Company

34.

Individual

Stephen R. Stafford

Georgia Transmission Corporation

35.

Individual

Greg Rowland

Duke Energy

36.

Individual

Armin Klusman

CenterPoint Energy

37.

Individual

Charles Lawrence

American Transmission Company

38.

Individual

Alice Murdock Ireland

Xcel Energy

39.

Group

Ben Li

IRC Standards Review Committee

X
X

Consideration of Comments on Relay Loadability Order — Project 2010-13

1. Attachment B is intended to contain the test that the Planning Coordinators must use to determine whether a sub-200kV facility is
critical to the reliability of the bulk power system. Do you agree that the method proposed in Attachment B is a technically sound
approach to determine whether a sub-200kV facility is critical to the reliability of the bulk power system?
Summary Consideration:

Organization

Yes or No

Question 1 Comment

Northeast Power Coordinating
Council

Support conformance with PRC-003 for all circuits 100 kV and above and as long as a reasonable period of
time is allowed for proper implementation. However, some circuits could be prioritized based on their criticality
to the system. The methodology in Attachment B should be considered as determining those circuits which
should be prioritized first, followed by the remaining circuits 100 kV and above. Further clarification is needed
for Criterion #2 because the circuits which make up an IROL can change depending upon the state of the
system, while evaluation of relay loadability must be done in advance. The following language is proposed:
Each circuit that is a monitored element of an IROL, assuming that all transmission elements are in service and
the system is under normal conditions.Criterion #3 is unclear. The term “directly related to” (off-site power
supply to nuclear plants”) is so broad that it essentially covers all transmission circuits that are connected to a
nuclear plant. If this criterion meant to be the circuits that are directly connected to a nuclear plant, and which
form a critical path to supply backup power to the plant, then the criterion should be clarified. For example,
some plants may have low voltage (4160 V) cross-connects or distribution voltage (13.8 kV) circuits that
provide off-site or qualified alternate AC power supplies to nuclear plants which are likely not going to be
subject to relay loadability concerns due to transmission events (or such circuits may simply be providing power
to office buildings). As written, it could be interpreted that such circuits may have to be considered as part of
this requirement. This is unnecessary. This criterion needs to be revised such that lower voltage circuits which
cannot be subjected to relay loadability concerns are explicitly excluded, and also to limit its applicability to
circuits that provide critical off-site power to nuclear plants as identified in the Nuclear Plant Interface
Requirements (NPIRs) provided by the Nuclear Plant Generator Operators to the applicable Transmission
Entities in accordance with NUC-001-2.Criterion #4 does not belong in this standard, and should be eliminated.
If the outage of an element causes unacceptable voltages elsewhere, appropriate actions should be taken to
address and remediate this issue. Conformance with PRC-023 is not going to solve the undesired
consequences of an outage, which could occur any time. NUC-001-2 already requires that the Nuclear Plant
Generator Operator and the applicable Transmission Entities: o coordinate on the testing, calibration and
maintenance of on-site and off-site power supply systems and related components (R9.3.3) o incorporate
the NPIRs into their planning analyses of the electric system (R3) o incorporate the NPIRs into their operating
analyses of the electric system (R4.1) o operate the electric system to meet the NPIRs (R4.2).Criterion #6
should be deleted. The PC and TP assess their future systems according to the performance requirements

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Pacific Northwest Small Public
Power Utility Comment Group

MRO's NERC Standards Review
Subcommittee

Question 1 Comment
stipulated in the TPL standards, including those in TPL-003. To require an entity to assess the impact of a
contingency that is not required by TPL-003 would go beyond the basic planning and design requirements.
Further, it raises the question on why do we single out the 100-200 kV facilities, but not all 200kV and above
facilities? Requirement R1 in the recent draft PRC-023 already asks for setting transmission line relays so they
do not operate at or below 115% of the highest seasonal 15-minute Facility Rating. This requirement is
applicable for conditions with and without faults on the system, and is sufficient to cover the testing condition
stipulated in the proposed Criterion #6. The system is neither planned nor operated to allow for two
overlapping outages without operator action in between. If this criterion is retained, it should be made
consistent with the requirements of TPL-003, where operator actions can be assumed between the first and
second contingencies.
The comment group agrees with all the criteria but number 6. Consider a local loop above 100 kV that is fed
from a single radial tap from the BES. Some regions continue to treat such radially fed systems as BES due to
the presence of normally open tie switches on the distribution system. It is conceivable that a multiple
contingency within the loop could cause one or more of the remaining un-faulted lines within the loop to
overload to beyond 115% of their short term ratings. While undesirable, such a scenario does not rise to the
level of a BES event. Even if the lines cannot overload, entities will be required to run simulations to prove nonapplicability where such systems should be excluded by simple inspection.The comment group suggests that
radially operated (operated is the key word here) systems be excluded.
In general, Midwest Reliability Organization’s NERC Standards Review Subcommittee (NSRS) agrees with the
proposed criteria. However, there should be further clarification and qualification of the criteria noted below.In
the introduction, the wording of “determine if that circuit needs to be evaluated for conformance with PRC-023”
does not clearly tie to Requirement R5.1 or use the same language. We suggest revised wording to more
clearly refer to Requirement R5.1 by using the more similar language of, “determine the circuits that are critical
to the reliability of the BES”.For Criteria #4, add the qualification that the outage condition is assessed for the
near term planning horizon (years 1 to 5), rather imply that the criteria includes consideration of the less certain
longer term planning horizon (years 6 to 10). We suggest adding the words, “for the near term planning
horizon”, to the end of criteria #4.For Criteria #6, clearly limit the types of double contingencies that should be
considered to those identified in TPL-003 (e.g. more severe Category B), rather than imply any and all double
contingencies beyond TPL-003. In addition, there is no bound on all the N-1-1 contingencies that must be
considered (in TPL-003, the planner is allow to at least restrict the scope of study to the more severe
contingencies. We suggest revising the wording to, “. . . as a result of double contingencies that are required in
the TPL-003 standard and in addition, the more severe contingencies of loss of a single circuit, followed by the
loss of a second circuit, without system adjustments in between”.We do not believe that a flowgate should be
automatically included in the criteria. The NERC Glossary of Terms definition of flowgate would require every
flowgate in the IDC to be identified. This is a problem because flowgates are included in the IDC for many
reasons not just because reliability issues are identified. Flowgates could be included to simply study the
impact of schedules on a particular interface as an example. It does not mean the interface is critical.

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

SERC Planning Standards
Subcommittee

Pepco Holdings, Inc. - Affiliates

System Protection Department

Question 1 Comment
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated monthly
and IDC users can add temporary flowgates at anytime. Criterion 1 would imply that any monitored facility then
becomes subject to the standard. Furthermore, IDC is more of a congestion management tool than a reliability
tool. FERC recognized this in Order 693, when they directed NERC to make clear in IRO-006 that the IDC
should not be relied upon to relieve IROLs that have been violated. Rather, other actions such as redispatch
must be used in conjunction. Thus, it would appear that inclusion of a flowgate in the IDC does not indicate
that it is critical.For Criteria #5, we suggest that the applicable entities be changed. The Transmission Planner
should be added because they have local planning responsibilities and knowledge that should be factored into
the consideration of critical circuit classification. We suggest that the Regional Entity be removed because it
does not fall within the Reliability Assurer functional tasks.
Although this question states Attachment B contains the critical facilities test, it instead appears to contain a
listing of facilities to evaluate to determine if they are critical, and not the test itself. Attachment B states that if
any of the criteria apply to a circuit, the circuit needs to be evaluated. It should state that the circuit should be
considered critical.Item1 should be removed since not all flowgates are related to reliability. The remaining
items adequately cover lines less than 200 kV that are critical to reliability.Item 3 contains a typo. Change "are"
to "is."Item 3: The word "related" is too vague, recommend to use the word "connected" instead.Item 6 is
confusing and should be revised as follows: "Each circuit operated between 100 kV and 200 kV that exceeds its
Short Term Emergency Rating by 15 percent or more as a result of double contingency combinations selected
by engineering judgment in TPL-003 Category C3, but without system adjustments in between." The comments
expressed herein represent a consensus of theviews of the above-named members of the SERC EC Planning
StandardsSubcommittee only and should not be construed as the position ofSERC Reliability Corporation, its
board, or its officers.
Mitigation timeframes are identified on the unofficial comment form, which differ from those defined by the
implementation plan in the most recent draft version of the standard. To be enforceable all mitigation
timeframes need to be identified in the standard itself. Secondly, the mitigation timeframes in the comment
form use phrases like “by the time the overload problem would be expected” and “before the operating time
being analyzed”. The timeframe requirements for mitigation need to be better defined to be auditable. The
Planning Coordinator needs to determine an “exact date” when the mitigation is required prior to the overload
taking place. If that date is more than 24 months away then the protection system owner will have to mitigate
the facility before the required date established by the Planning Coordinator. However, if the projected
overload date is less than 24 months away, the protection system owner will have 24 months after being
notified by the Planning Coordinator to mitigate the facility; and operators shall be made aware of the loadability
limitation and should operate the facility accordingly until the facility is mitigated. The issue is that it may take
24 months for the protection system owner to make necessary hardware upgrades to mitigate the loadability
limitation.
1. We think that criterion 1 should be changed as follows “... Texas Interconnection, or path in the Western
Interconnection that is listed as an Existing Path in the current year WECC Path Rating Catalog.” The current

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

FirstEnergy

Yes or No

Question 1 Comment
wording “rated path in the Western Interconnection” is too general and could be interpreted to mean any
element in the Western Interconnection that has a thermal rating.2. Change “are” in criterion 3 to “is.”3. We
think that criterion 5 is too vague, may be discriminatory, is unnecessary, and should be removed. There is no
basis listed for determining circuits in this criterion, the criterion may be applied discriminatorily or differently
even within the same interconnection, it potentially excludes the protection system owner from having input in
the process, and there is no redress for appeal by the owner. Protection system owners do not want
transmission elements to be removed from service due to loading and nothing precludes a protection system
owner from applying PRC-023 requirements to lower voltage lines. We also think that getting agreement
between the three required entities could be troublesome.If some form of criterion 5 is included in the
Attachment B, then it needs to define a technical basis for the request for inclusion, a procedure to initiate the
request for inclusion, due process defined for evaluation of the request, and inclusion of the protection system
owner in the evaluation process and the agreement. It seems that criterion 6 defeats the need for criterion 5.4.
We think that criterion 6 should be revised to read as “Each transmission line operated between 100 kV and
200 kV that exceeds its highest seasonal 15-minute Facility Rating or each transformer operated between 100
kV and 200 kV that exceeds its operator established emergency transformer rating as a result of a double
contingency...” The current wording would have no positive impact on BES reliability. First, the existing term
“Short Term Emergency Rating” is not defined and is not used in PRC-023. We are suggesting changing the
concept to terms that are used in the standard. Secondly, nothing in PRC-023 requires the protection system
owner to set the relays to operate at more than 115% of an emergency rating or a short term (15-minute) rating.
An element loading that qualifies under the drafting team's proposed criterion 6 would not have to be
considered unless it exceeded the 115% of the emergency or short term rating, which the protection system
settings would not be required to permit per the requirements of PRC-023. That is why we changed the
criterion to indicate inclusion of the element for any loading that exceeded the emergency or short term rating
for the contingencies studied.
FirstEnergy has the following comments related to the proposed criterion presented in the Attachment B of
PRC-023-2. A. Consistency with the CIP-002-4 bright-line criteria. When comparing the proposed PRC-023-2
Attachment B criterion to the bright-line criteria proposed for CIP-002-4 Attachment 1 Critical Asset
determination there is a great deal of overlap in concepts presented for transmission facilities. For example,
each cover aspects of transmission facilities associated with IROLs and transmission facilities that are
operationally significant for the safe operation and shutdown of a nuclear generation plant. Since these are
parallel standard development efforts we suggest to the extent possible the PRC team and CIP team use
consistent language when equivalent technical concepts are utilized for critical facility determinations.
FirstEnergy's suggested changes identified below for the six individual criterion are consistent with CIP-002-4
Attachment 1 proposals made by FirstEnergy. B. Leverage existing studies and analysis - planning timeframe.
We concur with the drafting team’s perspective that tests for the applicability of PRC-023 should leverage as
much existing work as possible, however, FE believes any study/analysis work should be limited to that
performed by the planning coordinators and transmission planners and not the transmission operators as

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Question 1 Comment
suggested by the comment form background information. FE believes the appropriate timeframe to identify the
sub 200kV critical facilities is the planning horizon based on forward looking studies conducted by or under the
supervision of the planning coordinator. This is consistent with PRC-023-1 (R3) and the proposed PRC-023-2
(R5) since the planning coordinator is the applicable entity required to determine the sub 200kV critical facilities
and the time-horizon for the requirement is long-term planning. Information based on analysis performed by the
reliability coordinator or transmission operator within the operating time horizon, such IROL, can be temporary,
dynamic and subject to change. Therefore, it should be clear that the intent of facilities associated with IROLs
are based on planning timeframe analysis. See FE's proposed changes to the second criterion. C. Mitigation
Timeframes. The comment form provided by the drafting team presented two criteria for mitigation timeframe.
This information should not be buried in a comment form but rather part or the standard's Effective Date's
section (Section 5) and presented in an Implementation Plan so that it may be fully vetted by industry through
the standards development process. The mitigation timeframe should be clear that the minimum expectation is
24-months upon the asset owner being notified by the planning coordinator of a new critical facility
determination. The first bulleted item presented by the team is vague if its meant to be the "greater of" or
"lesser of" 24 months or the time the overload problem would be expected. As stated above, FE believes that
critical facility determinations are appropriately based on planning horizon timeframes and therefore it should
be clear that an asset owner is afforded a minimum 24-month period to mitigate any critical facility required to
meet PRC-023. This is consistent with the approved version 1 and the proposed version 2 standard.D. Specific
comments on the Attachment B Criterion.i. Criteria 1: A flowgate should not be automatically included in the
criteria. The NERC Glossary of Terms definition of flowgate would require every flowgate in the IDC to be
identified. This is a problem because flowgates are included in the IDC for many reasons not just because
reliability issues are identified. Flowgates are used for market recognition to study the impact of schedules on a
particular interface and may not present a reliability concern. The team should consider a more limiting use of
flowgate or striking the criteria.ii. Criteria 2: FE agrees with the concept of associating a critical facility with
IROL however we believe two important revisions are required. First, the critical facility should be based on the
contingent facilities that describe the IROL and not the monitored elements. Second, the IROL determinations
should be based on planning horizon studies. FirstEnergy proposes the following text for criteria 2:
"Transmission Facilities that the Planning Coordinator or Transmission Planner designates that, if destroyed,
degraded, misused or otherwise rendered unavailable, demonstrates the need for an Interconnection Reliability
Operating Limit (IROL)."iii. Criteria 3: FE supports criteria 3 and proposes revision so that criteria 3 reads “BES
Facilities providing offsite power requirements as identified in the Nuclear Plant Interface Requirements.”iv.
Criteria 4: Criteria 4 should be removed since criteria 3, as revised above, should adequately cover the
transmission facilities deemed critical for a nuclear generation facility as designated in their NPIRs.v. Criteria 5:
Criteria 5 is vague, open ended and should be removed. Any criteria that the PC may use to include other
facilities should be explicitly stated in Attachment B. The RC should be removed since it makes evaluations
within the operating horizon timeframe which is not appropriate for requirement R5.vi. Criteria 6: FE supports
this criteria.

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Question 1 Comment

Midwest ISO Standards
Collaborators

Dominion

We have many concerns with the approach identified. We do not believe that a flowgate should be
automatically included in the criteria. The NERC Glossary of Terms definition of flowgate would require every
flowgate in the IDC to be identified. This is a problem because flowgates are included in the IDC for many
reasons not just because reliability issues are identified. Flowgates could be included to simply study the
impact of schedules on a particular interface as an example. It does not mean the interface is critical.
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated monthly
and IDC users can add temporary flowgates at anytime. Criterion 1 would imply that any monitored facility then
becomes subject to the standard. Furthermore, the IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to make clear in IRO-006 that the
IDC should not be relied upon to relieve IROLs that have been violated. Rather, other actions such as
redispatch must be used in conjunction. Thus, it would appear that inclusion of a flowgate in the IDC does not
indicate that it is critical.For criterion 2, we believe any contingent facility or prior outage that sets up the IROL
should be included if criterion 6 is revised to allow operator intervention between contingencies. If criterion 6 is
not revised, we do not support adding contingency or prior outages.For criterion 3, what does it mean to be
directly related to the off-site supply to nuclear plants? Does this means it is identified in the NPIRs associated
with the agreements mandated by NUC-001-2? This criteria needs to be further refined if retained.For criterion
4, since NERC standards collectively require us to operate the system to N-1 and to plan the system with
Category C contingencies, this criterion should never identify any facilities with low voltage.For criterion 5, this
criterion is too open ended and should be eliminated. Since the Regional Entity is the auditor, they should not
provide direct input into what is included. This seems like carte blanche for the Regional Entity to add to the list
of facilities whenever the latest issue arises. Could we end up having a situation where after every event
analysis the Regional Entity identifies even more facilities? If the Regional Entities have needs to identify
facilities they should do this by providing input through the standards development process to suggest
modifications to the criteria. Will the RC and PC be judged similar to how entities are currently being judged
regarding the number of Critical Assets that have been identified for CIP? If so, this could become a “bring me
a rock” exercise. If the PC and RC don’t identify enough facilities, will the ERO and Regional Entities pressure
them to identify more? Industry will be better served if we eliminate this open ended criteria and just identify
bright line criteria for what should be included. This really seems like a catch all in case we forget to add all
the necessary criteria.For criterion 6, we disagree with this criterion because it exceeds what is required in the
TPL standards. For category C3 contingencies, the Planning Coordinator is allowed to assume operator
intervention between the first and second independent contingency. Further, this even exceeds what FERC
ordered in their directive in paragraph 79 from Order 733 which states: “To achieve this goal, the test to
determine which sub-200 kV facilities are subject to PRC-023-1 must include or be consistent with the system
simulations and assessments that are required by the TPL Reliability Standards and meet the system
performance levels for all Category of Contingencies used in transmission planning.” This proposed criterion is
not consistent with the TPL standards but rather exceeds those standards.
While items 1-5 seem reasonable, Dominion takes exception with item six (6). Item six goes beyond TPL-003

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Bonneville Power Administration

PacifiCorp
Arizona Public Service Company
East Kentucky Power
Cooperative, Inc.

Yes
Yes
No

Question 1 Comment
criteria, by assuming the operator will have no time between contingency events to make system adjustments.
TPL-003 was thoroughly vetted when it was developed and is sound criteria that has been in place for years.
Circuits below 200 kV are less critical to the security of the bulk electric system. We see no reason why the
standard should not allow that the operator will make system adjustments between the first and second
contingency.
BPA would like to raise the concern regarding the terminology being used in PRC-023. An underlying principle
of the standard is to "Determine which of the facilities in its Planning Coordinator Area are critical to the
reliability of the BES...". BPA would like to take this opportunity to point out that determination of “critical” as
PRC-023 is applied may not be directly reflective of CIP Critical Asset identification. BPA feels this is
appropriate due to the guidance provided in CIP-002 R1 where the Risk-Based Assessment Methodology
should include the following considerations (as we used to develop BPA's methodology): 1) Control centers
and backup control centers; 2) Transmission substations that support the reliable operation of the Bulk Electric
System; 3) Generation resources that support the reliable operation of the Bulk Electric System; 4) Systems
and facilities critical to system restoration, including blackstart generators and substations in the electrical path
of transmission lines used for initial system restoration; 5) Systems and facilities critical to automatic load
shedding under a common control system capable of shedding 300 MW or more; 6) Special Protection
Systems that support the reliable operation of the Bulk Electric System; and 7) Any additional assets that
support the reliable operation of the Bulk Electric System that the Responsible Entity deems appropriate to
include in its assessment. No minimum kV levels are instructed to be specifically used to identify CIP Critical
Assets where PRC-023 is heavily driven by kV levels. BPA believes it would be very labor intensive to try and
come up with which circuits would exceed the STE rating by 15% or more. BPA would like to understand the
benefit of this study to increasing reliability.For Attachment B, BPA believes the performance requirement
needs to be clarified further. The term "double contingency" and reference to "TPL-003" needs to be more
specific, since TPL does cover more than just N-2 contingency of circuit elements. Additionally, regarding the
Standard itself, for some local areas, if three lines are feeding the local area and it has been planned per the
Standards (e.g. one single 115 kV line can't feed 100% of load in the area for loss of the other two), it seems
like if two of the lines are lost simultaneously, then loss of the third line quickly, rather than waiting for an
operator response may be preferable. This could be a safety issue and the operator may have no control over
outcome. Additional comments:BPA would find it helpful if the drafting team were to create a cross-walk of the
FERC directives (as listed on Page 3 and 4 of the SAR) and how/where the drafting team is addressing them.

East Kentucky Power Cooperative (EKPC) agrees in principle with the establishment of criteria to be used to
identify circuits to be evaluated for conformance with PRC-023-2. However, EKPC does not believe that all of
the proposed criteria are appropriate. For instance, the first listed criterion that specifies any circuit listed as the
monitored element of a flowgate appears to be excessive. EKPC does not believe that flowgates necessarily
correspond with a critical facility requiring further analysis of relay settings. EKPC also does not agree with the

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Southern Company

Yes

Salt River Project

Operational Compliance

Yes

California ISO
Piedmont EMC

No
Yes

Kansas City Power & Light

Question 1 Comment
6th listed criterion as stated. We propose that the criterion be modified to allow system adjustments between
contingencies in accordance with the TPL-003 standard. EKPC feels that this criterion stated in Attachment B
should maintain consistency with the requirements for system performance stated in TPL-003. With the
elimination of the first criterion listed in Attachment B and the modification of the 6th listed criterion to allow
system adjustments between contingencies, EKPC would support the method listed in Attachment B for
identification of critical circuits.
For clarity, it is suggested that the two sentences above the criteria list of Attachment B be revised as follows:
Review each (line and transformer) circuit less than 200 kV against the following criteria to determine if that
circuit must conform with PRC-023. If any of the criteria below apply to the circuit under review, the circuit must
conform to the requirements of PRC-023.
There is an error in the wording under R5, this requirement states "transmission lines operated at below 200kV
and transformers below 230kV." It should state "transmission lines operated between 100kV and 200kV and
transformers operated between 100kV and 200kV" otherwise this standard will fall out of the definition of BES.
We would like to propose a rewrite for criterion #6. The proposed rewrite is:"Each circuit operated between 100
kV and 200 kV that exceeds its short term Emergency Rating by 15% or more as the result of a double
contingency, beyond the requirements of TPL-003 C3 (i.e. loss of a single circuit followed by the loss of a
second circuit without manual system adjustments in between), for all combinations selected by engineering
judgment in the TPL-003 C3 analyses." Note - This modified TPL-003 C3 contingency reflects a situation where
a System Operator may not have time between two contingencies to make appropriate system
adjustments.The term “Short Term Emergency Rating” is not a defined term so “short term” should not be
capitalized and could potentially be removed. The definition of Emergency Rating specifies a finite time period.
The addition of the word 'manual' before 'system adjustment' mirrors the TPL-003 C3 definition and better
clarifies what is meant by 'system adjustment' as this is not a defined term. This would then imply that
automatic system adjustments that occur due to RAS and SPS operations, transformer tap changes and
automatic switching of reactive resources would not constitute a 'system adjustment' in the context of this
criterion (further supported by the note to criterion #6).
Further clarifications to the criteria in Attachment B are required.
I would like to have a provision in the Standard so that all radial transmission lines are excluded from this
requirement since they are not used for load transfer. Otherwise, a lot of utilities will have to comply wiht this
Standard by stating that we do not have any critical lines and have a letter from the TO stating that we don't
have any critical lines.
Do not agree with the approach in R5 and R5.1 in proposed Standard PRC-023-2 to dictate to the Planning
Coordinator additional criteria beyond the TPL Standards to identify operating sensitivities. The proposed
Appendix B proposes to establish additional considerations of facilities by which the Planning Coordinator must
determine if those facilities are critical to the reliability of the BES. There are a variety of differing, and often
complex, operating conditions that dictate the need for transmission facilities. The TPL standards require
extensive studies of the transmission system be performed under steady state and dynamic conditions to

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

United Illuminating

Yes

Ingleside Cogeneration, LP

ISO New England Inc.

Question 1 Comment
understand and identify sensitive areas of the transmission system and enable Reliability Coordinators to
identify flowgates and other operating sensitivities in their respective regions. In light of the Reliability
Coordinators awareness of transmission sensitivities through these studies, it seems unnecessary to dictate to
the Reliability Coordinators additional criteria as proposed here in this Appendix B.
We agree with the approach. We are concerned that the periodicity of the determination of the lines between
100 kV and 200 kV is not specified in Attachment B number 6 or R5. Is this an annual determination or
performed only when a study for the Planning Horizon is completed. Is the study period the short term planning
horizon (1-5 year) or long-term planning horizon (6-10 year)? For a temporary maintenance condition, e.g. a
line is removed from service for 14 months, is the PC required to reevaluate the list of facilities?
In paragraph 97 of Order 733, FERC allows for entities to challenge the identification of sub-200 kV
transmission facilities as critical to the BES. The paragraph reads as follows:”Finally, commenters argue that
there should be some mechanism for entities to challenge criticality determinations. We agree that such a
mechanism is appropriate and direct the ERO to develop an appeals process (or point to a process in its
existing procedures) and submit it to the Commission no later than one year after the date of this Final
Rule.”Most of the proposed criteria leverage well-understood concepts such as violations of IROLs or double
contingencies. However, the proposed attachment includes a catchall statement under Criterion #5 that the
RC, PC, and RE can designate circuits as critical without any defined basis. This makes an appeals process
imperative since there are economic impacts to facility owners of such designations. This process needs to be
proposed and evaluated by the industry concurrently with Appendix B, not at a future date.
General comment: ISO New England supports conformance with PRC-003 for all circuits 100 kV and above
allowing for a reasonable period of time for proper implementation. However, some circuits could be prioritized
based on their criticality to the system. The methodology in Attachment B should be considered as determining
those circuits which should be prioritized first, followed by the remaining circuits 100 kV and above. Comments
regarding specific criteria:2. Further clarification is needed regarding criterion #2, since the circuits which make
up an IROL can change depending upon the state of the system while evaluation of relay loadability must be
done in advance. We proposed the following language: Each circuit that is a monitored element of an IROL,
assuming that all transmission elements are in service and the system is under normal conditions.”3. The
breadth of criterion #3 is unclear and may, as written, be broader than necessary or appropriate. For example,
some plants may have low voltage (4160 V) cross-connects or distribution voltage (13.8 kV) circuits that
provide off-site or qualified alternate AC power supplies to nuclear plants which are likely not going to be
subject to relay loadability concerns due to transmission events (or such circuits may simply be providing power
to office buildings). As written, it could be interpreted that such circuits may have to be considered as part of
this requirement, and we believe this to be unnecessary. This criterion needs to be modified such that lower
voltage circuits which cannot be subjected to relay loadability concerns are explicitly excluded and also to limit
its applicability to circuits that provide critical off-site power to nuclear plants, as identified in the Nuclear Plant
Interface Requirements (NPIRs) provided by the Nuclear Plant Generator Operators to the applicable
Transmission Entities in accordance with NUC-001-2.4. Criterion #4 should be eliminated. NUC-001-2 already

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Manitoba Hydro

ComEd

Yes

MidAmerican Energy

Question 1 Comment
requires that the Nuclear Plant Generator Operator and the applicable Transmission Entities: o coordinate on
the testing, calibration and maintenance of on-site and off-site power supply systems and related components
(R9.3.3) o incorporate the NPIRs into their planning analyses of the electric system (R3) o incorporate the
NPIRs into their operating analyses of the electric system (R4.1) o operate the electric system to meet the
NPIRs (R4.2).6. Criterion #6 is overly stringent and should be deleted. The system is neither planned nor
operated to allow for two overlapping outages without operator action in between. If this criterion is retained, it
should be made consistent with the requirements of TPL-003, where operator actions can be assumed
between the first and second contingencies.
1) For criteria #5, Regional Entity does not need to be involved in determining the operational significant
circuits. It should be changed to: “Each circuit determined and agreed to by the Reliability Coordinator and the
Planning Coordinator.”2) For criteria #6, it should be clarified that it would be up to the Planning Coordinator to
make the engineering judgment in determining the double contingencies beyond the requirements of TPL-003
standard. In addition, there should be some coordination between the methodology for critical asset
determination in the cyber security standards and the relay loadability standard so multiple assessments are
not required by the Planning Coordinator. Ideally, the scope of the TPL assessment should provide sufficient
information for the other relevant NERC standards.
Criteria number 6 calls for a test that includes comparison to the “Short Term Emergency Rating”. We have
had some confusion on exactly which rating this refers to. Thus, our comment is to add some clarifications to
this term. For example if this is the rating that is closest to a 15 minute highest seasonal facility rating, state
this directly or in a footnote.
The proposed criteria is not technically sound as many of the criteria are completely arbitrary and have no
technical basis. The appropriate basis for a critical element is something that could result in instability,
uncontrolled separation, or cascading which is the basis for all NERC standards, the 2003 blackout, and the
Energy Policy Act wording. The following proposed criteria is not technically sound and should be deleted:1.
Being a flowgate or monitored element of a flowgate. The loss of a flowgate that doesn’t result in the instability,
uncontrolled separation or cascading, may pose no more jeopardy to grid reliability than any other element that
isn’t designated as a flowgate. This was proved by FERC’s own TIER report.2. A circuit agreed to by the RC,
PC, and RE. This has absolutely no technical basis whatever and is completely arbitrary. This requirement
also completely excludes the actual owner / operator of the facilities.3. A circuit that exceeds 15% of its shortterm emergency rating as a result of a double contingency. This criteria exceeds what is required in the TPL
standards. For category C3 contingencies, the Planning Coordinator is allowed to assume operator
intervention between the first and second independent contingency. Further, this even exceeds what FERC
ordered in their directive in paragraph 79 from Order 733 which states: “To achieve this goal, the test to
determine which sub-200 kV facilities are subject to PRC-023-1 must include or be consistent with the system
simulations and assessments that are required by the TPL Reliability Standards and meet the system
performance levels for all Category of Contingencies used in transmission planning.” This proposed criterion is
not consistent with the TPL standards but rather exceeds those standards. This completely ignores any

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

MEAG Power

Yes

EROCT

American Electric Power

Question 1 Comment
unusual or temporary operating conditions that could result from ice storms or even maintenance practices.
A minor clarification is needed. The first line under Criteria reads,"Review each circuit (line and transformer)
less than 200 kV needs ..." It needs to be reworded as follows: "Review each circuit (line and low-side
transformer) between 100 kV and 200 kV needs ..."The first line of number 6 needs to be reworded by deleting
"between 100 kV and 200 kV." It would now read, " EAch circuit operated that exceeds its Short Term ..."
In response to Attachment B of PRC-023, ERCOT ISO respectfully submits the following comments:Criterion 1
- the phrase “Commercially Significant Constraint in the Texas Interconnection” and the associated footnote
should be removed. Commercially Significant Constraints (CSCs) are market-driven constraints designed to
economically manage congestion under the ERCOT Zonal market construct. CSCs are not reliability
constraints that reflect the criticality of an element relative to system reliability. Furthermore, as noted in
footnote 1 in Attachment B, the ERCOT market is transitioning from the current Zonal construct to a Nodal
construct on December 1, 2010. Under the Nodal design CSCs will not exist. Accordingly, the rules that apply
to CSCs will expire prior to the implementation of this rule.Criterion 3 - The word “are” should be replaced with
the word “is”.Criterion 4 - There should not be any circuits whose outage causes unacceptable voltages on the
off-site power bus at a nuclear plant. Therefore, this criterion should be removed.Criterion 6 - Short Term
Emergency Rating is not a defined term. Accordingly, it is not clear what rating is at issue. Emergency Rating is
a defined term, and ERCOT assumes that is the rating envisioned by this criticality identifier. If that is the case,
it needs to be clarified. If some other rating is envisioned, that too needs to be clarified, because, as noted,
Short Term Emergency Rating is not defined.
These AEP comments are provided in the context of the primary goal of this standard as specified under R5,
"... to prevent cascading ...". The fundamental concern behind these comments is that the implemented
methodology should not unnecessarily and erroneously classify facilities as “critical”, even for the limited
purposes of this single standard. Such labels should only be applied to facilities that are truly “critical” to the
reliability of the Bulk Electric System, and thus, the implemented methodology should only identify “critical”
facilities. In addition, the implementation plan must allow for ample time to mitigate the initial wave of “critical”
facilities that would reasonably be expected to be significantly larger than the incremental number of new
“critical” facilities that will be identified on a routine basis going forward. Specific comments on the posted
criteria being proposed by NERC are outline below.(1) Flowgates in the Eastern Interconnection (and
Commercially Significant Constraints in the Texas Interconnection) are defined for various reasons and not just
for reliability purposes. Flowgates are defined for interface monitoring, congestion management, and other
purposes unrelated to reliability. Many of the flowgates reflect nominal normal and emergency ratings to limit
loadings on these facilities below their thermal capabilities, and not for the purpose of preventing cascading.
As such, being part of a flowgate definition alone should not be the basis for suspecting susceptibility to
cascading, and thus, not a good reason for having such facilities meet the requirements of this standard.
Furthermore, flowgates are updated on a continuous, and many times, temporary basis, and thus, not a
practical basis for identifying facilities for the purposes of this standard. Therefore, this criterion should not be
used as a basis for defining “critical” facilities for the purposes of this standard.(2) Since the identification of

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Question 1 Comment
“critical” facilities is made by the Planning Coordinators in the planning horizon (to give the relay owners ample
time to address compliance with the requirements of this standard), then the IROL methodology that is
applicable to the planning horizon (as specified under FAC-010) must be used to identify such “critical”
facilities. In the case of PJM, IROL facilities in the planning horizon are those SOL facilities that have been
identified as potentially resulting in cascading outages. As such, system reinforcements are developed in the
planning horizon to ensure that such cascading conditions are mitigated and do not materialize in the eventual
operating horizon. Consequently, PJM does not define any IROL facilities in the planning horizon. Therefore,
this criterion can not be used as a basis for defining “critical” facilities in the planning horizon for the purposes
of this standard. On the other hand, IROL facilities identified in the operating horizon (as specified under FAC011), would be appropriate to use to identify “critical” facilities for the purposes of this standard.(3) On the
surface, this appears to be a reasonable criterion. However, need to clarify what is meant by “directly related”.
If these are facilities that are identified under the NPIRs mandated under NUC-001, then their associated relay
loadability performance should be addressed under NUC-001. Moving this requirement from PRC-023 to NUC001 will ensure that all requirements associated with nuclear plants are addressed together under the same
standard (NUC-001).(4) On the surface, this appears to be a reasonable criterion. However, when such
voltage studies are conducted and unacceptable voltage conditions are identified in the planning horizon,
system reinforcements and other mitigating actions are taken to ensure that such conditions do not occur in the
operating horizon. Consequently, since no such conditions will be allowed to remain, then no “critical” facilities
should result from this criterion. On that basis, this criterion should be eliminated. If the criterion is kept, then it
should be moved under NUC-001 for the same reasons noted under criterion 3. Also, the criterion needs to
specify the starting point of the outage analysis that identifies the unacceptable voltages. Furthermore, the
outaged facility needs to be subject to heavy loadings to be considered for possible designation as a “critical”
facility. The outage of the facility for reasons unrelated to heavy loadings should not be a basis for making that
facility subject to the requirements of this standard.(5) This criterion is too open ended and should be
eliminated. As the auditing entity, the Reliability Entity should not be providing any input outside of the auditing
process. The Planning Coordinator has the flexibility to engage any other entities as it sees fit, and thus, there
is no need to single out the Reliability Coordinator under this criterion. Also, even if these entities were kept
and others, such as the Transmission Owners, were added, what would be the basis that these entities would
use to identify these “critical” facilities? Again, this criterion is too open ended, it does not add anything
meaningful to the effort, and thus, it should be eliminated.(6) On the surface, this appears to be a rational basis
for identifying “critical” facilities since it utilizes cascading simulations. However, it stops short of performing the
N-1-1-1 simulations (declares all overloaded facilities after the N-1-1 simulations as “critical” rather than going
the extra step of performing the N-1-1-1 simulations to determine if any additional facilities become overloaded)
that are needed to demonstrate susceptibility to cascading. Furthermore, an additional filter, one that takes into
consideration the amount of load that would be placed at risk by the N-1-1-1 cascading scenario, also needs to
be incorporated into this methodology. This can best be achieved by giving the TOs an opportunity to review
the preliminary results from their Planning Coordinator and to demonstrate to their Planning Coordinator as to

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Minnesota Power

Independent Electricity System
Operator

Ameren

Question 1 Comment
the amount of load that would be at risk through the cascading of the proposed “critical” facilities. If the TOs
can successfully demonstrate to their Planning Coordinator that for certain facilities the amount of load that
would be at-risk (from the cascading scenario) falls below a specified threshold level (to be determined by their
Planning Coordinator), then those facilities would be excluded from the final list of “critical” facilities. In the end,
this should be the only criterion that is used to identify “critical” facilities for the purposes of this standard.
Regarding the use of Short Term Emergency Ratings in the simulations, it should be noted that most ratings
used in planning base cases (the ones that would be used by the Planning Coordinator) are Long Term
Emergency Ratings, and thus, converting such models to reflect Short Term Emergency Ratings just for the
purposes of conducting these simulations would not be practical. Therefore, the specification should be made
as a higher percentage of Long Term Emergency Ratings.
Minnesota Power recommends that the Standards Drafting Team consider changing item #6 to read as
follows:Each circuit operated between 100 kV and 200 kV that exceeds its Short Term Emergency Rating by 15
percent or more as a result of a double contingency (for those combinations selected by engineering judgment
in TPL-003 System Performance Following Loss of Two or More BES Elements analyses).
We agree with Criteria # 1, 2 and 5, but do not agree with Criteria #3, #4 and #6.Criterion #3 is unclear. The
term “directly related to” (off-site power supply to nuclear plants” is so broad that it essentially covers all
transmission circuits that are connected to a nuclear plant. If this criterion meant to be the circuits that are
directly connected to a nuclear plant and which form a critical path for supply backup power to the plant, then
the criterion should say so to provide better clarity.Criterion #4 does not belong in this standard. If the outage of
an element causes unacceptable voltages elsewhere, appropriate actions should be taken to address and
remediate this issue. Conformance with PRC-023 is not going to solve the undesired consequences of an
outage, which could occur any time. Criterion #6 is troublesome and perhaps not needed. The PC and TP
assess their future systems according to the performance requirements stipulated in the TPL standards,
including those in TPL-003. To require an entity to assess the impact of a contingency that is not required by
TPL-003 would go beyond the basic planning and design requirements. Further, it raises the question on why
do we single out the 100-200 kV facilities, but not all 200kV and above facilities? Requirement R1 in the recent
draft PRC-023 already asks for setting transmission line relays so they do not operate at or below 115% of the
highest seasonal 15-minute Facility Rating. This requirement is applicable for conditions with and without faults
on the system, and is sufficient to cover the testing condition stipulated in the proposed Criterion #6. We
suggest to remove this Criterion #6.
Criterion #1 : A monitored flowgate does not imply a reliability issue. Flowgates are monitored for many
reasons, some for reliability and some to regulate the amount of firm transmission service. In non-FTR markets,
firm transmission monitoring may be a partial function of reliability. However, in FTR markets, the sale of firm
transmission service may be related to the acquisition of ARR/FTRs. Under these scenarios, the flowgate may
be in place to ensure FTR funding sufficiency. Circuits with high degrees of uncertain loading are most
susceptible but the mere presence of uncertainty does not make them critical for the reliability of the
BES.Criterion #2: We are ok with the element related to “IROL” type criterion including outage of such element

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

WECC

Pacific Gas and Electric Company

Question 1 Comment
causing instability or cascading effect on the BES. Criterion #3: We believe that our comment should be
restated as “This criterion should not be included in a relay loadability test. The fact that a circuit supplies a
reserve aux transformer at a nuclear plant does not make the circuit critical to the transmission network or to
the plant. If the outage of a circuit results in the outage or instability of a nuclear plant, then these issues
should have been addressed in the design of the plant supply and/or in the TPL-002 assessment.”Criterion 4:
This issue should be covered in TPL-002 or NUC-001. This item should not be included in a relay loadability
test.Criterion #5: This is an open-ended criterion without any supporting basis. It is also unclear who at the
Regional Entity would “sign-off”, Compliance, Engineering, or someone else? Further, this type of criterion
would introduce more inconsistencies rather uniformity. If such a criterion is used, we suggest that the RC, PC,
and/or RE should work closely with the local Transmission Planners to determine if a circuit should be
assessed for criticality and further subjected to the relay loadability test.Criterion #6: Short Term Emergency
Rating, although capitalized in here, is not a NERC defined term. Further, the criterion does not identify the
time duration that the STE rating would be applicable, nor the basis for such a rating. If a common time
duration and basis for rating could be established, a common loading above the STE rating could be
established. A loading of 120% may be more indicative of a cascade than 115%, and would be applicable for
fast acting contingencies involving multiple circuits, including Category C1 bus faults, C2 breaker failures, or C5
double-circuit tower outages. We do not agree with the proposal that system adjustments would not be allowed
for slower multiple contingency Category C3 events (sometimes referred to as N-1-1 outages) involving lines,
generators or transformers, as this requirements clearly steps on standard TPL-003.
The approach described is reasonable, however, it would be more comprehensive and consistent to replace in
item 1 (Attachment B), "rated path in the Western Interconnection" with "paths included in Table of Major
WECC Transfer Paths in the Bulk Electric System". This Table is more comprehensive because it is identified
by the WECC Operating Committee and is consistent with the major paths used in other WECC Standards.Item
5 appears vague. What does “agreed to by the Reliability Coordinator, the Planning Coordinator, and Regional
Entity mean?” Do all three need to be in agreement before a facility is to be added to the list to be evaluated, or
can any one of them add it to the list? How are these entities supposed to come to agreement and document
that agreement. If there is not a proactive effort to develop the list and “agree” to it, there probably won’t be a
list.I’m not sure I understand Item 6. Does this mean that results of TPL-003 assessments will helpt identify
circuits that have to be evaluated? TPL-003 is eventually going to go away when the ATFNSDT effort is
completed. The requirement to conduct the types of assessments currently included in TPL-003 will not go
away, but the specific referenct to TPL-003 could become obsolete.
We believe the approach described is reasonable, however, as written Item 1 (Attachment B) concerning
WECC paths is vague. We suggest, replacing "rated path in the Western Interconnection" with "paths included
in Table of Major WECC Transfer Paths in the Bulk Electric System". We believe referencing this Table would
provide clarity because the paths in this Table are identified by the Operating Committee in WECC and are
consistent with the major paths used in other WECC Standards, such as FAC-501-WECC-1, PRC-004-WECC1, and TOP-007-WECC-1.

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Question 1 Comment

Georgia Transmission
Corporation

Duke Energy

CenterPoint Energy

American Transmission Company

Criterion 6 of Attachment B states "Each circuit operated between 100 kV and 200 kV that exceeds its Short
Term Emergency Rating by 15 percent or more as a result of a double contingency..." The basis for the 15
percent criterion has not been clearly explained. What is the basis for this criterion? Based on this criterion,
multiple lines could be identified as critical facilities, when, in fact, loss of these lines could have no significant
impact to the BES(i.e. not cause cascading outages on the BES).
o General Comment - It should be made clear that the application of these criteria is intended to determine
which facilities must be evaluated for applicability of PRC-023-2 and may not necessarily dictate modification of
relay settings. Situations where there is time for operator intervention, or no cascading, wouldn’t need
loadability protection. o Criteria 1 - We do not believe that flowgates should be automatically included as a
criteria, since a flowgate may be in the IDC for business reasons. Also, the list of flowgates is dynamic. o
Criteria 2 - Monitored elements of an IROL are also dynamic and we question how you could apply this in the
planning timeframe so it could be used to set relays. IROLs identified in the planning horizon should be
mitigated by some action prior to reaching the operating horizon. This criteria is not specific enough to be
applied consistently. o Criteria 3 - What is meant by “directly related”? There is a difference between normal
off-site power and emergency power. We don’t think the NPIRs would clarify this situation. Is the expectation
that no lines connected to a nuclear plant trip except for a fault on the line? o Criteria 4 - If we had such a
circuit it would violate TPL-002 as well as the NPIRs, so this is not a useful criteria, because you’ll never
identify anything with it. o Criteria 5 - It doesn’t make sense to include the Regional Entity, because the
Regional Entity doesn’t do the analysis. Also, this criteria just says you can go beyond the existing criteria,
which is always an option - so why include it as a criteria? o Criteria 6 - “Short Term Emergency Rating” is not
a defined term. However its use in conjunction with the 15% overload suggests that a 15-minute Emergency
Rating is what is intended. Some Transmission Owners haven’t determined sufficiently short term Emergency
Ratings to meet the intent of this criteria, and if they set their relays at 115% of their shortest term Emergency
Rating they would restrict loadability more than the standard should allow. Regardless of how the criteria for
contingency line loading are defined in Attachment B, the criteria should match the requirements of PRC-023-2.
Considering situations where the transmission system may be at risk of cascading outages or voltage collapse,
CenterPoint Energy believes sub-200 kV elements should be considered operationally significant only
whenever reasonably contemplated scenarios would cause high amperage and low voltage to be experienced
on the elements. Criteria 6 that proposes loading greater than 15% of the short term emergency rating
following a double contingency is not a technically sound method to indicate if an element is operationally
significant. CenterPoint Energy recommends only criteria 1 through 5 be used to determine whether a sub-200
kV element is operationally significant to the reliability of the bulk power system.
In general, we agree with the proposed criteria. However, we propose the following changes to the introduction,
Criteria #4 and Criteria #6. [[1]]- In the introduction, the wording of “determine if that circuit needs to be
evaluated for conformance with PRC-023” does not clearly refer to Requirement R5.1 or use the same
language as R5.1. We believe that the wording in Attachment B should match the wording in R5.1. However,
use of the terminology, “critical to reliability of the BES”, keeps causing confusion with the meaning of the

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Xcel Energy

IRC Standards Review Committee

Question 1 Comment
concept of “critical” as it is defined in the CIP-002 standard. Therefore, we propose replacing the “critical”
terminology in R5.1 with distinctly different terminology like, “that have major operational significance to the
reliability of the BES”. Then, use wording similar to R5.1 in Attachment B such as, “determine the circuits that
have major operational significance to the reliability of the BES”. [[2]]- For Criteria #4, add the qualification that
the outage condition is assessed for the near term planning horizon (years 1 to 5), rather imply that the criteria
includes consideration of the less certain longer term planning horizon (years 6 to 10). We suggest adding the
words, “for the near term planning horizon”, to the end of criteria #4. [[3]]- For Criteria #6, clearly limit the types
of double contingencies that should be considered to those identified in TPL-003 (e.g. more severe Category
B), rather than imply any and all double contingencies beyond TPL-003. In addition, there is no bound on all the
N-1-1 contingencies that must be considered (in TPL-003, the planner is allow to at least restrict the scope of
study to the more severe contingencies. We suggest revising the wording to, “. . . as a result of double
contingencies that are required in the TPL-003 standard and in addition, the more severe contingencies of loss
of a single circuit, followed by the loss of a second circuit, without system adjustments in between”.
Item 1 - it is not clear how ‘temporary flowgates’ would be considered I this application; “commercial”
considerations should not be part of a reliability standard; “rated path” in WECC is not clear - are these any
path in the WECC Path Catalog, or is it intended to mean the “Major WECC Paths...”?Item 4 - we feel it should
be eliminated from the list of criteria. Since NERC standards collectively require us to operate the system to N1 and to plan the system with Category C contingencies, this criterion should never identify any facilities with
low voltage.Item 5 - this appears to give carte blanche authority to the PC/RC/RE to decide a circuit is subject
to evaluation; we believe this should be tempered with concurrence from the TO/GO/DP.

Criterion 1 is inappropriate and should be eliminated. It states that any monitored facility below 200KV would
be subject to this standard. A facility that is designated as a flowgate should NOT be automatically assumed
to have an impact on reliability. Flowgates are included in the IDC for many reasons and not always because
the facilities are critical to bulk system reliability. Some flowgates are defined and included in the IDC only to
have the PTDF, OTDF and LODF calculated. In general, flowgates are not a good indicator for reliability needs;
the master list of IDC flowgates is updated monthly and IDC users can add temporary flowgates at anytime.
Furthermore, IDC is primarily used to study congestion and is the basis of Transmission Loading Relief (TLR)
which is not a reliability tool. FERC recognized this in Order 693, when they directed NERC to make clear in
IRO-006 that the IDC should NOT be relied upon to relieve IROLs that have been violated and other actions
such as redispatch must be used in conjunction with TLR. Criterion 2 should state that any contingent facility
or prior outage that sets up the IROL be included, except where such facility is used as a proxy for assessing
the IROL. Criterion 3 is unclear and should be clarified. What does it mean to be “directly related” to the offsite supply to nuclear plants? More clarity in the wording is needed. Is the intent that facilities that provide
off-site power to nuclear plants as defined in the NPIRs associated with the agreements mandated by NUC001-2 are captured in this standard?Criterion 4 is not needed since NERC standards already contain

Consideration of Comments on Relay Loadability Order — Project 2010-13

Organization

Yes or No

Question 1 Comment

requirements to operate the system to N-1 and to plan the system with Category C contingencies. Therefore,
this criterion would never identify any facilities whose outage would cause low voltage.Criterion 5 is too open
ended and should be eliminated. The Regional Entity serves primarily as the compliance enforcement
authority and not the technical assessor of what facilities are critical for bulk power reliability. They do not
perform any of the operating and planning functions required to comply with reliability standards. These
criteria should strive to be as close as possible to “bright line” tests. Criterion 5 is in a sense rhetorical, like
defining a word with the same word.Criterion #6 should be deleted. This criterion does not recognize that the
system is neither planned nor operated to allow for two overlapping outages without operator action in
between. This goes beyond the assessment and performance requirements of TPL-003, where operator
actions can be assumed between the first and second contingencies. We also ask why a 15% over Short Term
Emergency Rating is an appropriate level, there is no justification.

END OF REPORT

Unofficial Comment Form for Relay Loadability Order (No. 733) (Project
2010-13)
Please DO NOT use this form. Please use the electronic form located at the link below to
submit FORMAL comments on the proposed second version of the Relay Loadability
Standard PRC-023-2 that includes the applicability test in Attachment B. The electronic
comment form must be completed by December 16, 2010.
If you have questions please contact Joe Bucciero at joe.bucciero@gmail.com or by
telephone at 267-981-5445.
Background Information
NERC Standard PRC-023-1 – Transmission Relay Loadability was approved by FERC as
mandatory and enforceable in March 2010, with direction that NERC make a number of
changes.
The Standard Drafting Team made changes to PRC-023-1 to address the following directives
from Order 733
• p. 60 . . . modify PRC-023-1 to apply an “add in” approach to sub-100 kV facilities that
are owned or operated by currently-Registered Entities or entities that become
Registered Entities in the future, and are associated with a facility that is included on a
critical facilities list defined by the Regional Entity.
• p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.
• p. 203 . . . modify sub-requirement R1.10 so that it requires entities to verify that the
limiting piece of equipment is capable of sustaining the anticipated overload for the
longest clearing time associated with the fault.
• p. 224 . . . make available for review to users, owners and operators of the Bulk-Power
System, by request, a list of those facilities that have protective relays set pursuant to
sub-requirement R1.12.
• p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]
• p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.
• p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on
the list of relays and protection systems that are specifically subject to the Reliability
Standard.
• p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.
• p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.
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609.452.8060 | www.nerc.com

Comment Form — Project 2010-13 — PRC-023-2 Standard (Order 733)

The Standard Drafting Team posted the proposed changes for informal industry comment
from August 19, 2010 to September 19, 2010. The proposed changes did NOT include
Attachment B to the standard as it was still a work in progress at that time. Attachment B
contains the applicability test that the Planning Coordinators must use to determine whether
a sub-200kV facility must comply with PRC-023. The inclusion of a test is a directive in
Order No. 733:
• p. 69 . . . modify Requirement R3 of the Reliability Standard to specify the test that
planning coordinators must use to determine whether a sub-200 kV facility is critical to
the reliability of the Bulk-Power System.
Requirement R6 of the draft PRC-023-2 standard (formerly Requirement R3 of PRC-023-1)
states:
R6. Each Planning Coordinator shall apply the criteria in Attachment B to an assessment
conducted at least once each calendar year, with no more than 15 months between
assessments, to determine which transmission Elements must comply with this standard.
The Planning Coordinator shall:
[Violation Risk Factor: High] [Time Horizon: Long Term Planning]
6.1 Apply the criteria to transmission lines that are operated at 100 kV to 200 kV and
transformers with low voltage terminals connected at 100 kV to 200 kV.
6.2 Apply the criteria to transmission lines operated below 100 kV and transformers
with low voltage terminal connections below 100 kV, if the Regional Entity has
identified either of these Element types as critical facilities for the purposes of the
Compliance Registry and they are in its Planning Coordinator Area.
6.3 Maintain a list of facilities determined according to the process described in
Requirement R6.
6.4 Include on the list the year studied for which criterion B4 in Attachment B first
applies when a facility is added and only criterion B4 is applicable.
6.5 Provide a list of facilities to all Regional Entities, Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within its
Planning Coordinator Area within 30 calendar days of the establishment of the
initial list and within 30 calendar days of any changes to that list.
In response to comments during the informal posting the SDT has replaced the phrase
“critical to reliability of the bulk electric system” with “must comply with this standard.” The
SDT notes that although the phrase “critical to reliability of the bulk electric system”
appears in the approved PRC-023-1 and is used in Order No. 733, the SDT recognizes that
use of the same or similar terms in multiple standards will result in confusion.
Use of the phrase “critical to reliability of the Bulk Electric System” in PRC-023 is intended
to have meaning specific to the issue of relay loadability; specifically to identify facilities,
that if they trip due to relay loadability following an initiating event, may contribute to
undesirable system performance similar to what occurred during the August 2003 blackout.
Reliability is adequately addressed in Attachment B since it identifies all of the facilities that
must be subject to this standard to maintain reliability of the Bulk Electric System.

Comment Form — Project 2010-13 — PRC-023-2 Standard (Order 733)
A Blue Ribbon Panel was formed by NERC to develop that required Attachment B to PRC023-2, which was separately posted for informal industry comment from September 23,
2010 to October 12, 2010.
Applicability Testing Criteria
NERC Reliability Standard PRC-023 — Transmission Relay Loadability was developed in
answer to relay loadability problems highlighted during the blackout of 2003. Relay
loadability has been either causal or contributory to a majority of major system
disturbances dating back to the 1965 blackout and beyond. The proposed Standard is
intended to prevent circuits from prematurely tripping due to relay loadability when
thermally overloaded. The concept is to allow some time for system operators to intervene
and alleviate the overloads.
If any circuit trips under adverse conditions, even if the loss of that circuit does not itself
cause a cascade, the resultant weakened transmission system leaves the bulk electric
system more exposed to possible cascading outages. Therefore, applicability of PRC-023
should not only be for operationally significant circuits that could cause a cascade, but also
for circuits that are prone to overloads (relievable through operator action) during
contingencies.
Planning coordinators test for conformance with the TPL standards through various
contingency analyses that should prevent critical circuits from becoming overloaded. The
TPL criteria contingencies studied normally screen for susceptibility to cascading and system
instability. However, overloading of circuits for short periods of time is permissible, and
assumes operator action can alleviate such overloads in a timely fashion. Although the
planning tests are fairly rigorous, they are usually limited to N-1 or N-2 level contingencies.
However, it is for the unforeseen combinations of outages that assurance is necessary that
circuits would not trip for relay loadability reasons.
The recommendations stemming from the 2003 blackout called for review of circuits 200 kV
and above. Logically, all circuits, including those below 200 kV, that are operationally
significant to the reliability of the bulk electric system (BES) should be tested for
susceptibility.
System studies go to great lengths to determine transfer capabilities on critical transmission
interfaces. Planning and operational studies are routinely conducted to determine the
transfer capabilities of circuits such as those that are part of interconnection reliability
operating limits (IROLs), flowgates in the Eastern Interconnection, major transfer paths in
the Western Interconnection, or comparable monitored elements in the Texas
Interconnection or Québec Interconnection. Any circuit that is important enough to
reliability to be actively managed to prevent overloads should also be important enough to
prevent it from inadvertently tripping due to relay loadability for combinations of outages
that are not normally tested.
Note: The criteria included in Attachment B define the family of circuits operated below 200
kV that must comply with PRC-023. If the protection systems on these circuits comply with
the Requirements of PRC-023, no further action is necessary. Any protection systems that
do not comply would require mitigation.

Comment Form — Project 2010-13 — PRC-023-2 Standard (Order 733)
Implementation Timeframes
Requirement R1: the first day of the first calendar quarter after applicable regulatory
approvals or in those jurisdictions where no regulatory approval is required, the first
calendar quarter after Board of Trustees adoption except as noted below.
• For the addition to Requirement R1, criterion 10, to set transformer fault protection
relays and transmission line relays on transmission lines terminated only with a
transformer such that the protection settings do not expose the transformer to fault
level and duration that exceeds its mechanical withstand capability, the first day of
the first calendar quarter 12 months after applicable regulatory approvals or in those
jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter 12 months after Board of Trustees adoption.
• For supervisory elements as described in PRC-023 - Attachment A, section 1.6, the
first day of the first calendar quarter 24 months after applicable regulatory approvals
or in those jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter 24 months after Board of Trustees adoption.
Requirements R2 and R3: the first day of the first calendar quarter after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter after Board of Trustees adoption.
Requirements R4 and R5: the first day of the first calendar quarter six months after
applicable regulatory approvals or in those jurisdictions where no regulatory approval is
required the first day of the first calendar quarter six months after Board of Trustees
adoption.
Requirement R6: the first day of the first calendar quarter 18 months after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
Requirement R7: the first day of the first calendar quarter after applicable regulatory
approvals or in those jurisdictions where no regulatory approval is required, the first day of
the first calendar quarter after Board of Trustees adoption.
Questions
The SDT has considered all of the industry comments submitted during the informal
comment period, and has revised and updated the PRC-023-2 standard to incorporate the
comments received in this posting of the complete standard. Your responses to the
following questions will assist the SDT for Project 2010-13 Relay Loadability Order 733 in
finalizing the work for PRC-023-2 relative to the proposed modifications summarized above.
For each question, please indicate whether or not you agree with the requirement being
proposed. If you disagree with the changes to the proposed requirement, please explain
why you disagree and provide as much detail as possible regarding your disagreement
including any suggestions for altering the proposed requirement that would eliminate or
minimize your disagreement. The SDT would appreciate responses to as many of these
questions as you are willing to supply.
1. Requirement R1 defines the criteria for any specific circuit terminal to prevent its phase
protective relay settings from limiting transmission system loadability while maintaining
reliable protection of the BES for all fault conditions. Criterion 10 of Requirement R1
was modified to ensure that protection settings do not expose transformers to fault level
and duration that exceeds their mechanical withstand capability. Do you agree with the

Comment Form — Project 2010-13 — PRC-023-2 Standard (Order 733)
modification to criterion 10 in Requirement R1? If not, please explain and provide
specific suggestions for improvement.
Yes
No
Comments:
2. Requirement R2 requires the evaluation of out-of-step blocking schemes to verify that
the out-of-step blocking elements allow tripping of phase protective relays for faults that
occur during the loading conditions used to verify transmission line relay loadability per
Requirement R1. Note this new Requirement R2 does not add a new obligation on
Transmission Owners, Generator Owners, and Distribution Providers; it only explicitly
states in PRC-023-2 an obligation that presently is included in Attachment A, section 2
of PRC-023-1. Do you agree with the requirement included in Requirement R2? If not,
please explain and provide specific suggestions for improvement.
Yes
No
Comments:
3. Requirement R4 requires the Registered Entities that choose to utilize Requirement R1
criterion 2 as the basis for verifying transmission line relay loadability to provide the
Planning Coordinator, Transmission Operator, and Reliability Coordinator with a list of
facilities associated with those transmission line relays at least once each calendar year,
with no more than 15 months between reports. Do you agree with the requirement
included in Requirement R4? If not, please explain and provide specific suggestions for
improvement.
Yes
No
Comments:
4. Requirement R5 requires the Registered Entities that set transmission line relays
according to Requirement R1 criterion 12 to provide a list of the facilities associated with
those relays to the Regional Entity at least once each calendar year, with no more than
15 months between reports. Do you agree with the requirement included in
Requirement R5? If not, please explain and provide specific suggestions for
improvement.
Yes
No
Comments:
5. Requirement R6 requires each Planning Coordinator to apply the criteria in Attachment B
to determine which transmission Elements must comply with this standard. Do you
agree with the requirement included in Requirement R6? If not, please explain and
provide specific suggestions for improvement.
Yes
No
Comments:
6. "Requirement R7 requires the Registered Entities to implement Requirement R1,
Requirement R2, Requirement R3, Requirement R4, and Requirement R5 for each facility
that the Planning Coordinator added to the list of facilities that must comply with this

Comment Form — Project 2010-13 — PRC-023-2 Standard (Order 733)
standard (per Requirement R6) by certain dates following notification by the Planning
Coordinator. Do you agree with the requirement included in Requirement R7? If not,
please explain and provide specific suggestions for improvement.
Yes
No
Comments:
7. Attachment A, section 1.6 has been revised to avoid unintended negative impact on
reliability associated with referring to “Protective functions that supervise operation of
other protective functions.” Section 1.6 has been revised to “Supervisory elements
associated with current-based, communication-assisted schemes where the scheme is
capable of tripping for loss of communications” to be more specific to the concern stated
in Order No. 733. Do you agree that this is an acceptable and effective method of
meeting this directive? If not, please explain and provide specific suggestions for
improvement.
Yes
No
Comments:
8. Attachment B contains the test that the Planning Coordinators must use to determine
which transmission elements (transmission lines operated below 200 kV and
transformers with low voltage terminals connected below 200 kV) must comply with this
standard. Do you agree that the method proposed in Attachment B is a technically sound
approach? If not, please explain and provide specific suggestions for improvement.
Yes
No
Comments:

Implementation Plan for PRC-023-2: Transmission Relay Loadability
Standards Involved

• PRC-023-2 —Transmission Relay Loadability
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or approved, that
must be implemented before the Transmission Relay Loadability standard can be implemented.

Proposed Effective Date
Requirement R1: the first day of the first calendar quarter after applicable regulatory approvals or in those
jurisdictions where no regulatory approval is required, the first calendar quarter after Board of Trustees adoption
except as noted below.
• For the addition to Requirement R1, criterion 10, to set transformer fault protection relays and transmission
line relays on transmission lines terminated only with a transformer such that the protection settings do not
expose the transformer to fault level and duration that exceeds its mechanical withstand capability, the first
day of the first calendar quarter 12 months after applicable regulatory approvals or in those jurisdictions
where no regulatory approval is required, the first day of the first calendar quarter 12 months after Board of
Trustees adoption.
• For supervisory elements as described in PRC-023 - Attachment A, section 1.6, the first day of the first
calendar quarter 24 months after applicable regulatory approvals or in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter 24 months after Board of Trustees
adoption.
Requirements R2 and R3: the first day of the first calendar quarter after applicable regulatory approvals or in those
jurisdictions where no regulatory approval is required, the first day of the first calendar quarter after Board of
Trustees adoption.
Requirements R4 and R5: the first day of the first calendar quarter six months after applicable regulatory approvals
or in those jurisdictions where no regulatory approval is required the first day of the first calendar quarter six
months after Board of Trustees adoption.
Requirement R6: the first day of the first calendar quarter 18 months after applicable regulatory approvals or in
those jurisdictions where no regulatory approval is required the first day of the first calendar quarter 18 months after
Board of Trustees adoption.
Requirement R7: the first day of the first calendar quarter after applicable regulatory approvals or in those
jurisdictions where no regulatory approval is required, the first day of the first calendar quarter after Board of
Trustees adoption.

Applicability
Requirements within the proposed standard apply to:
4.1.

Functional Entities:

116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Implementation Plan for PRC-023-2: Transmission Relay Loadability

4.2.

4.1.1

Transmission Owners with load-responsive phase protection systems as described in PRC023 - Attachment A, applied to facilities defined in 4.2.1 through 4.2.6.

4.1.2

Generator Owners with load-responsive phase protection systems as described in PRC-023Attachment A, applied to facilities defined in 4.2.1 through 4.2.6.

4.1.3

Distribution Providers with load-responsive phase protection systems as described in PRC023- Attachment A, applied according to facilities defined in 4.2.1 through 4.2.6, provided
those facilities have bi-directional flow capabilities.

4.1.4

Planning Coordinators

Facilities:
4.2.1

Transmission lines operated at 200 kV and above.

4.2.2

Transmission lines operated at 100 kV to 200 kV that the Planning Coordinator has
determined are required to comply with this standard.

4.2.3

Transmission lines operated below 100 kV that Regional Entities have identified as critical
facilities for the purposes of the Compliance Registry and the Planning Coordinator has
determined are required to comply with this standard.

4.2.4

Transformers with low voltage terminals connected at 200 kV and above.

4.2.5

Transformers with low voltage terminals connected at 100 kV to 200 kV that the Planning
Coordinator has determined are required to comply with this standard.

4.2.6

Transformers with low voltage terminals connected below 100 kV that Regional Entities
have identified as critical facilities for the purposes of the Compliance Registry and the
Planning Coordinator has determined are required to comply with this standard

Other entities may be recipients of data as described in this standard, but have no requirements placed upon them.

Retired Standards
The following standard will be retired when PRC-023-2 becomes effective:
•

PRC-023-1 — Transmission Relay Loadability will be completely retired once PRC-023-2 becomes
effective as specified above.

November 1, 2010

Anticipated Date

1. Develop third draft of the standard and respond to comments.

December 2010 –
January 2011

2. Conduct recirculation ballot of standard

January 2011

3. NERC Board approval

February 2011

4. Submit standard to FERC for approval

March 2011

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability

A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-2

Transmission Owners with load-responsive phase protection systems as
described in PRC-023 - Attachment A, applied to facilities defined in 4.2.1
through 4.2.6.

4.1.2

Generator Owners with load-responsive phase protection systems as described in
PRC-023- Attachment A, applied to facilities defined in 4.2.1 through 4.2.6.

4.1.3

Distribution Providers with load-responsive phase protection systems as
described in PRC-023- Attachment A, applied according to facilities defined in
4.2.1 through 4.2.6, provided those facilities have bi-directional flow capabilities.

4.1.4

Planning Coordinators

4.2. Facilities:
4.2.1 Transmission lines operated at 200 kV and above.
4.2.2 Transmission lines operated at 100 kV to 200 kV that the Planning Coordinator has
determined are required to comply with this standard.
4.2.3 Transmission lines operated below 100 kV that Regional
Entities have identified as critical facilities for the
purposes of the Compliance Registry and the Planning
Coordinator has determined are required to comply with
this standard.

FERC Order 733, ¶60: Apply
an “add in” approach to sub100 kV facilities.

4.2.4 Transformers with low voltage terminals connected at 200 kV and above.
4.2.5 Transformers with low voltage terminals connected at 100 kV to 200 kV that the
Planning Coordinator has determined are required to comply with this standard.
4.2.6 Transformers with low voltage terminals connected below 100 kV that Regional
Entities have identified as critical facilities for the purposes of the Compliance
Registry and the Planning Coordinator has determined are required to comply with
this standard.
5.

Effective Dates:
5.1. Requirement R1: the first day of the first calendar quarter
after applicable regulatory approvals or in those jurisdictions
where no regulatory approval is required, the first calendar
quarter after Board of Trustees adoption, except as noted below.

FERC Order 733, ¶284:
Remove the exceptions
footnote from the “Effective
Dates” section.

5.1.1 For the addition to Requirement R1, criterion 10, to set transformer fault protection
relays and transmission line relays on transmission lines terminated only with a

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
transformer such that the protection settings do not expose the transformer to fault
level and duration that exceeds its mechanical withstand capability, the first day of
the first calendar quarter 12 months after applicable regulatory approvals or in
those jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter 12 months after Board of Trustees adoption.
5.1.2 For supervisory elements as described in PRC-023 - Attachment A, section 1.6, the
first day of the first calendar quarter 24 months after applicable regulatory
approvals or in those jurisdictions where regulatory approval is not required, the
first day of the first calendar quarter 24 months after Board of Trustees adoption.
5.2. Requirements R2 and R3: the first day of the first calendar quarter after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter after Board of Trustees adoption.
5.3. Requirements R4 and R5: the first day of the first calendar quarter six months after
applicable regulatory approvals or in those jurisdictions where no regulatory approval is
required the first day of the first calendar quarter six months after Board of Trustees
adoption.
5.4. Requirement R6: the first day of the first calendar quarter 18 months after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
5.5. Requirement R7: the first day of the first calendar quarter after applicable regulatory
approvals or in those jurisdictions where no regulatory approval is required, the first day
of the first calendar quarter after Board of Trustees adoption.
B. Requirements
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1, criteria 1 through 13) for any specific circuit terminal
to prevent its phase protective relay settings from limiting transmission system loadability
while maintaining reliable protection of the BES for all fault conditions. Each Transmission
Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per
unit voltage and a power factor angle of 30 degrees. [Violation Risk Factor: High] [Mitigation
Time Horizon: Long Term Planning].
Criteria:
1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal
Facility Rating of a circuit, for the available defined loading duration nearest 4 hours
(expressed in amperes).
2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal
15-minute Facility Rating 1 of a circuit (expressed in amperes).
3. Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
•

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at
each end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate
at or below the maximum power transfer capability of the line, determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with Requirement R1, criterion 3, using the
full line inductive reactance.

5. Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes).
6. Set transmission line relays applied on transmission lines connected to generation stations
remote to load so they do not operate at or below 230% of the aggregated generation
nameplate capability.
7. Set transmission line relays applied at the load center terminal, remote from generation
stations, so they do not operate at or below 115% of the maximum current flow from the
load to the generation source under any system configuration.
8. Set transmission line relays applied on the bulk system-end of transmission lines that serve
load remote to the system so they do not operate at or below 115% of the maximum current
flow from the system to the load under any system configuration.
9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the to the under any system configuration.
10. Set transformer fault protection relays and transmission line
relays on transmission lines terminated only with a
transformer such that the protection settings do not expose
the transformer to fault level and duration that exceeds its
mechanical withstand capability and so that the relays do
not operate at or below the greater of:

FERC Order 733, ¶203: Modify
sub-requirement R1.10 to verify
equipment is capable of
sustaining the anticipated
overload associated with the
fault.

•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

•

115% of the highest operator established emergency transformer rating.

11. For transformer overload protection relays that do not comply with the loadability
component of Requirement R1, criterion 10 set the relays according to one of the
following:
•

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
•

12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.
b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
c. Include a relay setting component of 87% of the current calculated in Requirement
R1, criterion 12 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

Each Transmission Owner, Generator Owner, and
FERC Order 733, ¶244: Include
Distribution Provider shall verify that its out-of-step
section 2 of Appendix A as an
blocking elements allow tripping of phase protective relays
additional Requirement.
for faults that occur during the loading conditions used to
verify transmission line relay loadability per Requirement
R1. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

R3.

R4.

FERC Order 733, ¶186: Modify
Each Transmission Owner, Generator Owner, and
R1.2 to require that TOs, GOs,
Distribution Provider that chooses to use Requirement R1
and DPs give their TOPs a list of
criterion 2 as the basis for verifying transmission line relay
transmission facilities that
loadability shall provide its Planning Coordinator,
implement R1.2.
Transmission Operator, and Reliability Coordinator with a
list of facilities associated with those transmission line relays at least once each calendar year,
with no more than 15 months between reports [Violation Risk Factor: Lower] [Time Horizon:
Long Term Planning]

R5.

Each Transmission Owner, Generator Owner, and
Distribution Provider that sets transmission line relays
according to Requirement R1 criterion 12 shall provide a list
of the facilities associated with those relays to its Regional
Entity at least once each calendar year, with no more than
15 months between reports, to allow entities to know which
facilities have protective relay settings that limit the

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
facility’s capability. [Violation Risk Factor: Lower] [Time Horizon: Long Term Planning]
R6.

R7.

Each Planning Coordinator shall apply the criteria in Attachment B to an assessment conducted
at least once each calendar year, with no more than 15 months between assessments, to
determine which transmission Elements must comply with this standard. The Planning
Coordinator shall: [Violation Risk Factor: High] [Time Horizon: Long Term Planning]
6.1

Apply the criteria to transmission lines that are operated at 100 kV to 200 kV and
transformers with low voltage terminals connected at 100 kV to 200 kV.

6.2

6.3

Maintain a list of facilities determined according to the
process described in Requirement R6.

6.4

Include on the list the year studied for which criterion
B4 in Attachment B first applies when a facility is
added and only criterion B4 is applicable.

6.5

Provide a list of facilities to all Regional Entities,
Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution
Providers within its Planning Coordinator Area within 30 calendar days of the
establishment of the initial list and within 30 calendar days of any changes to that list.

FERC Order 733, ¶237:
Modify sub-requirement
R3.3 to add the RE to
list of entities that
receive the critical
facilities list.

Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
Requirement R1, Requirement R2, Requirement R3, Requirement R4, and Requirement R5 for
each facility that is added to the Planning Coordinator’s list of facilities that must comply with
this standard pursuant to Requirement R6, Part 6.5 by the later of the first day of the second
calendar quarter 24 months following notification by the Planning Coordinator of a facility’s
inclusion on such a list or the first day of the first calendar quarter of the year in which
Attachment B criterion B4 first applies. [Violation Risk Factor: High] [Time Horizon: Long
Term Planning]

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
M4. The Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 2 shall have evidence such as dated
correspondence to show that they provided its Planning Coordinator, Transmission Operator,
and Reliability Coordinator with a list of facilities associated with those transmission line
relays. (R4)
M5. The Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided a list of the facilities associated with those relays to its
Regional Entity. (R5)
M6. The Planning Coordinator shall have evidence such as power flow results, calculation
summaries, or study reports that they used the criteria established within Attachment B to
determine the facilities that must comply with this standard as described in Requirement R6.
The Planning Coordinator shall have a dated list of such facilities and shall have evidence such
as dated correspondence that it provided the list to the Regional Entities, Reliability
Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its
Planning Coordinator Area.
M7. The Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as dated spreadsheets, summaries of calculations, and study reports, that it implemented
the Requirements within the specified timeframe per Requirement R7.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
1.2. Data Retention
The Transmission Owner, Generator Owner, Distribution Provider and Planning Coordinator
shall keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation to demonstrate compliance with Requirements R1 through R5 and R7 for
three calendar years.
The Planning Coordinator shall retain documentation of the most recent review process
required in R6. The Planning Coordinator shall retain the most recent list of facilities that are
critical to the reliability of the electric system determined per R6.
If a Transmission Owner, Generator Owner, Distribution Provider or Planning Coordinator is
found non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time specified above, whichever is longer.
The Compliance Monitor shall keep the last audit record and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
None.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability

Violation Severity Levels:

Requirement
R1

Lower
N/A

Moderate
N/A

High
N/A

N/A

The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that
occur during the loading
conditions used to verify
transmission line relay loadability
per Requirement R1.

N/A

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.
R4

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, Regional
Entity, and Reliability Coordinator
with a list of facilities that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

The responsible entity did not
provide its Regional Entity, with a
list of facilities that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 12 at least once each
calendar year, with no more than
15 months between reports.

N/A

The Planning Coordinator used the
criteria established within
Attachment B to determine which
transmission Elements, described
in 6.1 and 6.2, in its Planning
Coordinator area must comply
with the standard and met parts 6.3
through 6.5, but more than 15
months and less than 24 months
lapsed between assessments.

The Planning Coordinator failed to
use the criteria established within
Attachment B to determine which
transmission Elements, described
in 6.1 and 6.2, in its Planning
Coordinator area must comply
with the standard.

Draft 2: November 1, 2010

OR
The Planning Coordinator used the
criteria established within
Attachment B, at least once each

Standard PRC-023-2 — Transmission Relay Loadability
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard and
met 6.3 and 6.5 but failed to
include the year studied for which
criterion B4 in Attachment B first
applies when a facility is added
and only criterion B4 is applicable
(part 6.4).
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard and
met 6.3 and 6.4 but provided the
list of facilities to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator Area within
31days and 45 days after the list
was established or updated (part
6.5).

The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard and
met 6.3 and 6.4 but provided the
list of facilities to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator Area within
46 days and 60 days after list was
established or updated (part 6.5).

calendar year, with no more than
15 months between assessments,
to determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard but
failed to meet parts 6.3, 6.4 and
6.5.
OR
The Planning Coordinator used the
criteria established within
Attachment B, at least once each
calendar year, with no more than
15 months between assessments,
to determine which transmission
Elements in its Planning
Coordinator area must comply
with the standard but failed to
apply the criteria to the Elements
described in parts 6.1 and 6.2.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard and
met 6.4 and 6.5 but failed to
maintain the list of facilities
determined according to the
process described in Requirement
R6 (part 6.3).
OR
The Planning Coordinator used the
criteria established within

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability

N/A

Draft 2: November 1, 2010

N/A

Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard and
met 6.3 and 6.4 but failed to
provide the list of facilities to the
Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution
Providers within its Planning
Coordinator Area or provided the
list more than 60 days after the list
was established or updated (part
6.5).
The Transmission Owner,
Generator Owner, or Distribution
Provider failed to implement
Requirement R1, Requirement R2,
Requirement R3, Requirement R4,
and Requirement R5 for each
facility that is added to the
Planning Coordinator’s list of
facilities that must comply with
this standard pursuant to
Requirement R6, Part 6.5 by the
later of the first day of the second
calendar quarter after 24 months
following notification by the
Planning Coordinator of a
facility’s inclusion on such a list
by the Planning Coordinator or the
first day of the first calendar
quarter of the year in which
Attachment B criterion B4 first
applies.

Standard PRC-023-2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.
Version History
Version

Date

Action

Change Tracking

February 12,
2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe
VSL for Requirement 3 — “then” should be
“than.”

Errata

March 18, 2010

Approved by FERC

November 1, 2010

Revised to address directives from Order 733

Draft 2: November 1, 2010

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

1.6. Supervisory elements associated with current-based,
communication-assisted schemes where the scheme is capable of
tripping for loss of communications.

FERC Order 733, ¶264: Revise
section 1 of Attachment A to
include supervising relay
elements.

2. The following protection systems are excluded from requirements of
this standard:
2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications except as noted in
section 1.6

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
PRC-023 — Attachment B
Criteria
Review each applicable circuit against the criteria in this Attachment to
determine the facilities that must comply with the standard.
Applicable circuits include:

•
•

FERC Order 733, ¶69: Specify
the test that PCs must use to
determine whether sub-200 kV
facility is critical to reliability of
the BES

Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals
connected at 100 kV to 200 kV
Transmission lines operated below100 kV and transformers with low voltage terminals connected
below 100 kV that Regional Entities have identified as critical facilities for the purposes of the
Compliance Registry

If any of the following criteria apply to a circuit, the circuit must comply with the standard.
B1. Each circuit that is a monitored Element of a flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Element in the Texas Interconnection or Québec Interconnection, that has
been included to address long-term reliability concerns, as confirmed by the applicable Planning
Coordinator.
B2. Each circuit that is a monitored Element of an IROL where the IROL was determined in the longterm planning horizon.
B3. Each circuit that forms a path (as agreed to by the plant owner and the Transmission Entity) to
supply off-site power to nuclear plants.
B4. Each circuit identified through the following power flow analysis:
•

Simulate double contingency combinations selected by engineering judgment in TPL-003
Category C3, but without manual system adjustments in between (reflects a situation where a
System Operator may not have time between the two contingencies to make appropriate
system adjustments).

•

For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading
against the Facility Rating assigned for that circuit and used in the power flow case by the
Planning Coordinator.

•

When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.

•

The threshold for selection as a circuit that must comply with the standard will vary based on
the loading duration assumed in the development of the Facility Rating.
a. If the Facility Rating is based on a loading duration of up to and including four hours, the
circuit must comply with the standard if the loading exceeds 115% of the Facility Rating.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
b. If the Facility Rating is based on a loading duration greater than four and up to and
including eight hours, the circuit must comply with the standard if the loading exceeds
120% of the Facility Rating.
c. If the Facility Rating is based on a loading duration of greater than eight hours, the circuit
must comply with the standard if the loading exceeds 130% of the Facility Rating.
•

Radial circuits serving only load are excluded.

B5. Each circuit that the Planning Coordinator may include based on other technical studies or
assessments.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-2

Transmission Owners with load-responsive phase protection systems as
described in PRC-023 - Attachment A, applied to facilities defined belowin 4.2.1
through 4.2.6.

4.1.2

Generator Owners with load-responsive phase protection systems as described in
PRC-023- Attachment A, applied to facilities defined in 4.2.1 through 4.2.6.

4.1.3

4.1.4

Planning Coordinators

4.1.4.2.

Facilities:

4.1.14.2.1 Transmission lines operated at 200 kV and above.
4.2.2 Transmission lines operated at 100 kV to 200 kV that the Planning Coordinator has
determined are required to comply with this standard.
4.1.24.2.3 Transmission lines operated below 200 kV
FERC Order 733, ¶60: Apply
an “add in” approach to subdesignated by the Planning Coordinator 100 kV that
100 kV facilities.
Regional Entities have identified as critical to facilities for
the reliabilitypurposes of the Bulk Electric
SystemCompliance Registry and the Planning Coordinator has determined are
required to comply with this standard.
4.1.34.2.4 Transformers with low voltage terminals connected at 200 kV and above.
4.1.44.2.5 Transformers with low voltage terminals connected belowat 100 kV to 200 kV as
designated bythat the Planning Coordinator as critical to the reliability of the Bulk
Electric System (BES).has determined are required to comply with this standard.
4.2. Generator Owners with load-responsive phase protection systems as described in
Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.
4.3. Distribution Providers with load-responsive phase protection systems as described in
Attachment A, applied according to facilities defined in 4.1.1
FERC Order 733, ¶284:
through 4.1.4., provided that those facilities have bi-directional
Remove the exceptions
flow capabilities.
4.4. Planning Coordinators.

footnote from the “Effective
Dates” section.

4.2.6 Transformers with low voltage terminals connected below 100 kV that Regional
Entities have identified as critical facilities for the purposes of the Compliance
Registry and the Planning Coordinator has determined are required to comply with
this standard.
Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
5.

Effective Dates:
5.1. Requirement R1, Requirement R2, Requirement R3, Requirement R4:
5.1.1 For circuits described in 4.1.1 and 4.1.3 above (except for switch-on-to-fault
schemes) —the beginning of: the first day of the first calendar quarter
followingafter applicable regulatory approvals.
5.2.5.1.
For circuits described in 4.1.2 and 4.1.4 above (including switch-on-to-fault
schemes) — at the beginning of the first calendar quarter 39 months following applicable
or in those jurisdictions where no regulatory approvals. approval is required, the first
calendar quarter after Board of Trustees adoption, except as noted below.
5.2.1 Each Transmission Owner, Generator Owner, and Distribution Provider shall have
24 months after being notified by its Planning Coordinator pursuant to
Requirement R5, Part 5.3 to comply with Requirement R1 (including all subrequirements) for each facility that is added to the Planning Coordinator’s critical
facilities list determined pursuant to Requirement R5, Part 5.1.
5.3. Requirement R5: 18 months following applicable regulatory approvals.
5.1.1 For the addition to Requirement R1, criterion 10, to set transformer fault protection
relays and transmission line relays on transmission lines terminated only with a
transformer such that the protection settings do not expose the transformer to fault
level and duration that exceeds its mechanical withstand capability, the first day of
the first calendar quarter 12 months after applicable regulatory approvals or in
those jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter 12 months after Board of Trustees adoption.
5.1.2 For supervisory elements as described in PRC-023 - Attachment A, section 1.6, the
first day of the first calendar quarter 24 months after applicable regulatory
approvals or in those jurisdictions where regulatory approval is not required, the
first day of the first calendar quarter 24 months after Board of Trustees adoption.
5.2. Requirements R2 and R3: the first day of the first calendar quarter after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter after Board of Trustees adoption.
5.3. Requirements R4 and R5: the first day of the first calendar quarter six months after
applicable regulatory approvals or in those jurisdictions where no regulatory approval is
required the first day of the first calendar quarter six months after Board of Trustees
adoption.
5.4. Requirement R6: the first day of the first calendar quarter 18 months after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
5.5. Requirement R7: the first day of the first calendar quarter after applicable regulatory
approvals or in those jurisdictions where no regulatory approval is required, the first day
of the first calendar quarter after Board of Trustees adoption.

B. Requirements
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1, Settings1criteria 1 through 13) for any specific circuit
terminal to prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the BES for all fault conditions, and to
prevent its out-of-step blocking schemes from blocking tripping for fault conditions.. Each

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
Transmission Owner, Generator Owner, and Distribution Provider shall evaluate relay
loadability at 0.85 per unit voltage and a power factor angle of 30 degrees:. [Violation Risk
Factor: High] [Mitigation Time Horizon: Long Term Planning].
SettingsCriteria:
1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal
Facility Rating of a circuit, for the available defined loading duration nearest 4 hours
(expressed in amperes).
2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal
15-minute Facility Rating1 of a circuit (expressed in amperes).
3. Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:
•

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at
each end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate
at or below the maximum power transfer capability of the line, determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with Requirement R1, Settingcriterion 3, using
the full line inductive reactance.

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
10. Set transformer fault protection relays and transmission
line relays on transmission lines terminated only with a
transformer such that the protection settings do not
expose the limiting piece of equipmenttransformer to
fault level and duration that exceeds its mechanical
withstand capability and so that the relays do not
operate at or below the greater of:

FERC Order 733, ¶203: Modify
sub-requirement R1.10 to verify
equipment is capable of
sustaining the anticipated
overload associated with the
fault.

•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

•

115% of the highest operator established emergency transformer rating.

11. For transformer overload protection relays that do not comply with the loadability
component of Requirement R1, Settingcriterion 10 set the relays according to one of the
following:
•

•

12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.
b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
c. Include a relay setting component of 87% of the current calculated in Requirement
R1, Settingcriterion 12 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
R2.R3.
Each Transmission Owner, Generator Owner, and Distribution Provider that uses a
circuit capability with the practical limitations described in Requirement R1, Settings.criterion
6, 7, 8, 9, 12, or 13 shall use the calculated circuit capability as the Facility Rating of the circuit
and shall obtain the agreement of the Planning Coordinator, Transmission Operator, and
Reliability Coordinator with the calculated circuit capability. [Violation Risk Factor: Medium]
[Time Horizon: Long Term Planning]
FERC Order 733, ¶186: Modify
R3.R4.
Each Transmission Owner, Generator Owner, and
R1.2 to require that TOs, GOs,
Distribution Provider that setschooses to use Requirement
and DPs give their TOPs a list of
R1 criterion 2 as the basis for verifying transmission line
transmission facilities that
relays according to Requirement R1 Setting 2relay
implement R1.2.
loadability shall provide its Planning Coordinator,
Transmission Operator, Regional Entity, and Reliability Coordinator with a list of facilities
associated with those transmission line relays at least once each calendar year, with no more
than 15 months between reports [Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]

R4.R5.
Each Transmission Owner, Generator Owner, and
Distribution Provider that sets transmission line relays
according to Requirement R1 Settingcriterion 12 shall
provide a list of the facilities associated with those relays to
its Regional Entity at least once each calendar year, with no
more than 15 months between reports., to allow entities to
know which facilities have protective relay settings that
limit the facility’s capability. [Violation Risk Factor:
Lower] [Time Horizon: Long Term Planning]
R6.

Each Planning Coordinator shall apply the criteria in Attachment B to an assessment conducted
at least once each calendar year, with no more than 15 months between assessments, to
determine which oftransmission Elements must comply with this standard. The Planning
Coordinator shall: [Violation Risk Factor: High] [Time Horizon: Long Term Planning]
6.1

Apply the facilities (criteria to transmission lines that are operated belowat 100 kV to
200 kV and transformers with low voltage terminals connected below 200 kV) at 100
kV to 200 kV.

6.16.2

Apply the criteria to transmission lines operated below 100 kV and transformers with
low voltage terminal connections below 100 kV, if the Regional Entity has identified
either of these Element types as critical facilities for the purposes of the Compliance
Registry and they are in its Planning Coordinator Area are critical to the reliability of
the BES to identify the facilities below 200 kV that must meet Requirement R1 to
prevent cascading when protective relay settings limit transmission loadability.
[Violation Risk Factor: High] [Time Horizon: Long Term Planning].

5.2

The Planning Coordinator shall have a process to use the criteria established within
Attachment B to determine the facilities that are critical to the reliability of the Bulk
Electric System.

6.3

Each Planning Coordinator shall maintain a currentMaintain a list of facilities
determined according to the process described in Requirement R5 Part 5.1R6.

6.4

Each Planning Coordinator shall provideInclude on the list the year studied for which
criterion B4 in Attachment B first applies when a facility is added and only criterion
B4 is applicable.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
6.46.5

R7.

Provide a list of facilities to itsall Regional
EntityEntities, Reliability Coordinators, Transmission
Owners, Generator Owners, and Distribution
Providers within its Planning Coordinator Area within
30 calendar days of the establishment of the initial list
and within 30 calendar days of any changes to that
list.

FERC Order 733, ¶237:
Modify sub-requirement
R3.3 to add the RE to
list of entities that
receive the critical
facilities list.

C. Measures
M1. The Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as spreadsheets or summaries of calculations to show that each of its transmission relays
is set according to one of the criteria in Requirement R1, criterion 1 through 13 and shall have
evidence such as coordination curves or summaries of calculations that show that relays set per
criterion 10 do not expose the transformer to fault levels and durations beyond those indicated
in the standard.
M2. The Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking
elements allows tripping of phase protective relays for faults that occur during the loading
conditions used to verify transmission line relay loadability per Requirement R1. (R2)
M3. The Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence such
as Facility Rating spreadsheets or Facility Rating database to show that they used the
calculated circuit capability as the Facility Rating of the circuit and evidence such as dated
correspondence that the resulting Facility Rating was agreed to by its associated Planning
Coordinator, Transmission Operator, and Reliability Coordinator. (R3)
M4. The Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 2 shall have evidence such as dated
correspondence to show that they provided its Planning Coordinator, Transmission Operator,
and Reliability Coordinator with a list of facilities associated with those transmission line
relays. (R4)
M5. The Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided a list of the facilities associated with those relays to its
Regional Entity. (R5)
M6. The Planning Coordinator shall have evidence such as power flow results, calculation
summaries, or study reports that they used the criteria established within Attachment B to
determine the facilities that must comply with this standard as described in Requirement R6.
The Planning Coordinator shall have a dated list of such facilities and shall have evidence such
as dated correspondence that it provided the list to the Regional Entities, Reliability

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability
Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its
Planning Coordinator Area.
M7. The Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as dated spreadsheets, summaries of calculations, and study reports, that it implemented
the Requirements within the specified timeframe per Requirement R7.
D. Compliance
1.

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
None.

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability

Violation Severity Levels:

Requirement
R1

Lower
N/A

Moderate
N/A

High
N/A

N/A

The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that
occur during the loading
conditions used to verify
transmission line relay loadability
per Requirement R1.

N/A

Draft 2: November 1, 2010

N/A

Draft 2: November 1, 2010

OR
The Planning Coordinator used the
criteria established within
Attachment B, at least once each

Draft 2: November 1, 2010

Standard PRC-023-2 — Transmission Relay Loadability

N/A

Draft 2: November 1, 2010

N/A

Standard PRC-023-2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.
Version History
Version

Date

Action

Change Tracking

February 12,
2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe
VSL for Requirement 3 — “then” should be
“than.”

Errata

March 18, 2010

Approved by FERC

November 1, 2010

Revised to address directives from Order 733

Draft 2: November 1, 2010

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

1.6. Protective functions that supervise operation of other
protective functions in 1.1 through 1.5.
1.6. Supervisory elements associated with current-based,
communication-assisted schemes where the scheme is capable of
tripping for loss of communications.

FERC Order 733, ¶264: Revise
section 1 of Attachment A to
include supervising relay
elements.

2. The following protection systems are excluded from requirements of this standard:
2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications. except as noted in
section 1.6

Draft 2: November 1, 2010

•
•

FERC Order 733, ¶69: Specify
the test that PCs must use to
determine whether sub-200 kV
facility is critical to reliability of
the BES

•

When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.

•

Draft 2: November 1, 2010

Radial circuits serving only load are excluded.

B5. Each circuit that the Planning Coordinator may include based on other technical studies or
assessments.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-12

Transmission Owners with load-responsive phase protection systems as
described in PRC-023 - Attachment A, applied to facilities defined belowin 4.2.1
through 4.2.6.

4.1.2

Generator Owners with load-responsive phase protection systems as described in
PRC-023- Attachment A, applied to facilities defined in 4.2.1 through 4.2.6.

4.1.3

4.1.4

Planning Coordinators

4.1.4.2.

Facilities:

4.1.14.2.1 Transmission lines operated at 200 kV and above.
4.2.2 Transmission lines operated at 100 kV to 200 kV as designated bythat the Planning
Coordinator has determined are required to comply with
this standard.

FERC Order 733, ¶60: Apply

an “add in” approach to sub4.1.24.2.3 Transmission lines operated below 100 kV that
100 kV facilities.
Regional Entities have identified as critical to facilities for
the reliabilitypurposes of the Bulk Electric
System.Compliance Registry and the Planning Coordinator has determined are
required to comply with this standard.

4.1.34.2.4 Transformers with low voltage terminals connected at 200 kV and above.
4.1.44.2.5 Transformers with low voltage terminals connected at 100 kV to 200 kV as
designated bythat the Planning Coordinator as criticalhas determined are required to
the reliability of the Bulk Electric Systemcomply with this standard.
4.2. Generator OwnersTransformers with load-responsive phase protection systems as described
in Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.
4.3. Distribution Providers with load-responsive phase protection systems as described in
Attachment A, applied according to facilities defined in 4.1.1
FERC Order 733, ¶284:
through 4.1.4., providedlow voltage terminals connected below
Remove the exceptions
100 kV that those facilitiesRegional Entities have bi-directional
footnote from the “Effective
flow capabilities.
Dates” section.

4.4. Planning Coordinators.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
5. Effective Dates 1:
5.1. Requirement 1, Requirement 2:
5.1.1 For circuits described in 4.1.1 and 4.1.3 above (except for switch-on-to-fault
schemes) —the beginning of the first calendar quarter following applicable
regulatory approvals.
5.1.2 For circuits described in 4.1.2 and 4.1.4 above (including switch-on-to-fault
schemes) — at the beginning of the first calendar quarter 39 months following
applicable regulatory approvals.
5.1.34.2.6 Each Transmission Owner, Generator Owner, and Distribution Provider shall
have 24 months after being notified by its identified as critical facilities for the
purposes of the Compliance Registry and the Planning Coordinator pursuant to
R3.3has determined are required to comply with R1 (including all sub-requirements)
for each facility that is added to the Planning Coordinator’s critical facilities list
determined pursuant to R3.1this standard.
5.

Effective Dates:
5.1. Requirement 3: 18 months followingR1: the first day of the first calendar quarter after
applicable regulatory approvals or in those jurisdictions where no regulatory approval is
required, the first calendar quarter after Board of Trustees adoption, except as noted
below.
5.1.1 For the addition to Requirement R1, criterion 10, to set transformer fault protection
relays and transmission line relays on transmission lines terminated only with a
transformer such that the protection settings do not expose the transformer to fault
level and duration that exceeds its mechanical withstand capability, the first day of
the first calendar quarter 12 months after applicable regulatory approvals or in
those jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter 12 months after Board of Trustees adoption.
5.1.2 For supervisory elements as described in PRC-023 - Attachment A, section 1.6, the
first day of the first calendar quarter 24 months after applicable regulatory
approvals or in those jurisdictions where regulatory approval is not required, the
first day of the first calendar quarter 24 months after Board of Trustees adoption.
5.2. Requirements R2 and R3: the first day of the first calendar quarter after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter after Board of Trustees adoption.
5.3. Requirements R4 and R5: the first day of the first calendar quarter six months after
applicable regulatory approvals or in those jurisdictions where no regulatory approval is
required the first day of the first calendar quarter six months after Board of Trustees
adoption.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
5.4. Requirement R6: the first day of the first calendar quarter 18 months after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
5.2.5.5.
Requirement R7: the first day of the first calendar quarter after applicable
regulatory approvals or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter after Board of Trustees adoption.
B. Requirements
R1.

Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (Requirement R1., criteria 1 through R1.13) for any specific circuit
terminal to prevent its phase protective relay settings from limiting transmission system
loadability while maintaining reliable protection of the Bulk Electric SystemBES for all fault
conditions. Each Transmission Owner, Generator Owner, and Distribution Provider shall
evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees:.
[Violation Risk Factor: High] [Mitigation Time Horizon: Long Term Planning].
Criteria:
a.1.Set transmission line relays so they do not operate at or below 150% of the highest seasonal
Facility Rating of a circuit, for the available defined loading duration nearest 4 hours
(expressed in amperes).
b.2.
Set transmission line relays so they do not operate at or below 115% of the
highest seasonal 15-minute Facility Rating2 of a circuit (expressed in amperes).
c.3.Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:
R1.•An infinite source (zero source impedance) with a 1.00 per unit bus voltage at
each end of the line.
R2.•An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.
d.4.
Set transmission line relays on series compensated transmission lines so
they do not operate at or below the maximum power transfer capability of the line,
determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with R1.Requirement R1, criterion 3, using the
full line inductive reactance.

e.5.Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes).

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
f.6. Set transmission line relays applied on transmission lines connected to generation stations
remote to load so they do not operate at or below 230% of the aggregated generation
nameplate capability.
g.7. Set transmission line relays applied at the load center terminal, remote from generation
stations, so they do not operate at or below 115% of the maximum current flow from the
load to the generation source under any system configuration.
h.8. Set transmission line relays applied on the bulk system-end of transmission lines that
serve load remote to the system so they do not operate at or below 115% of the maximum
current flow from the system to the load under any system configuration.
i.9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the load to the system under any system
configuration.
FERC Order 733, ¶203: Modify
j.10. Set transformer fault protection relays and transmission
line relays on transmission lines terminated only with a
transformer so that theysuch that the protection settings do
not expose the transformer to fault level and duration that
exceeds its mechanical withstand capability and so that the
relays do not operate at or below the greater of:

sub-requirement R1.10 to verify
equipment is capable of
sustaining the anticipated
overload associated with the
fault.

a.• 150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.
b.• 115% of the highest operator established emergency transformer rating.
k.11. For transformer overload protection relays that do not comply with R1.the loadability
component of Requirement R1, criterion 10 set the relays according to one of the
following:
•

Set the relays to allow the transformer to be operated at an overload level of at least
150% of the maximum applicable nameplate rating, or 115% of the highest operator
established emergency transformer rating, whichever is greater. The protection must
allow this overload, for at least 15 minutes to allowprovide time for the operator to
take controlled action to relieve the overload.

•

Install supervision for the relays using either a top oil or simulated winding hot spot
temperature element. The setting should be set no less than 100° C for the top oil
ortemperature or no less than 140° C for the winding hot spot temperature 3.

l.12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
1.a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
2.b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
3.c. Include a relay setting component of 87% of the current calculated in Requirement
R1., criterion 12.2 in the Facility Rating determination for the circuit.
m.13.Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

TheEach Transmission Owner, Generator Owner, orand
FERC Order 733, ¶244: Include
Distribution Provider shall verify that its out-of-step
section 2 of Appendix A as an
blocking elements allow tripping of phase protective relays
additional Requirement.
for faults that occur during the loading conditions used to
verify transmission line relay loadability per Requirement
R1. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

FERC Order 733, ¶186: Modify
The Planning Coordinator shall determine which of the
R1.2 to require that TOs, GOs,
facilities (transmission linesEach Transmission Owner,
and DPs give their TOPs a list of
Generator Owner, and Distribution Provider that chooses to
transmission facilities that
use Requirement R1 criterion 2 as the basis for verifying
implement R1.2.
transmission line relay loadability shall provide its
Planning Coordinator, Transmission Operator, and Reliability Coordinator with a list of
facilities associated with those transmission line relays at least once each calendar year, with
no more than 15 months between reports [Violation Risk Factor: Lower] [Time Horizon: Long
Term Planning]

R5.

R6.

Apply the criteria to transmission lines that are operated at 100 kV to 200 kV and
transformers with low voltage terminals connected at 100 kV to 200 kV) in its
Planning Coordinator Area are critical to the reliability of the Bulk Electric System to
identify the facilities from 100 kV to 200 kV that must meet Requirement 1 to prevent
potential cascade tripping that may occur when protective relay settings limit
transmission loadability. [Violation Risk Factor: Medium] [Time Horizon: Long Term
Planning].

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
R2.1.

The Planning Coordinator shall have a process to determine the facilities that are
critical to the reliability of the Bulk Electric System.
•

This process shall consider input from adjoining Planning Coordinators and
affected Reliability Coordinators.

6.2

The Planning Coordinator shall maintain a current Apply the criteria to transmission
lines operated below 100 kV and transformers with low voltage terminal connections
below 100 kV, if the Regional Entity has identified either of these Element types as
critical facilities for the purposes of the Compliance Registry and they are in its
Planning Coordinator Area.

o6.3

Maintain a list of facilities determined according to the
process described in R3.1Requirement R6.

6.4

The Planning Coordinator shall provideInclude on the
list the year studied for which criterion B4 in
Attachment B first applies when a facility is added and
only criterion B4 is applicable.

6.5

Provide a list of facilities to itsall Regional Entities, Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within 30its
Planning Coordinator Area within 30 calendar days of the establishment of the initial
list and within 30 calendar days of any changes to that list.

FERC Order 733, ¶237:
Modify sub-requirement
R3.3 to add the RE to
list of entities that
receive the critical
facilities list.

R3.R7.
Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
Requirement R1, Requirement R2, Requirement R3, Requirement R4, and Requirement R5 for
each facility that is added to the list. Planning Coordinator’s list of facilities that must comply
with this standard pursuant to Requirement R6, Part 6.5 by the later of the first day of the
second calendar quarter 24 months following notification by the Planning Coordinator of a
facility’s inclusion on such a list or the first day of the first calendar quarter of the year in
which Attachment B criterion B4 first applies. [Violation Risk Factor: High] [Time Horizon:
Long Term Planning]
C. Measures
M1. The Transmission Owner, Generator Owner, and Distribution Provider shall each have
evidence such as spreadsheets or summaries of calculations to show that each of its
transmission relays areis set according to one of the criteria in R1.Requirement R1, criterion 1
through 13 and shall have evidence such as coordination curves or summaries of calculations
that show that relays set per criterion 10 do not expose the transformer to fault levels and
durations beyond those indicated in the standard.
M1.M2. The Transmission Owner, Generator Owner, and Distribution Provider shall have
evidence such as spreadsheets or summaries of calculations to show that each of its out-of-step
blocking elements allows tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per Requirement R1.13.
(R1 (R2)
M2.M3. The Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to the criteria inRequirement R1., criterion 6, R1.7, R1.8, R1.9, R1.12, or
R.13 shall have evidence such as Facility Rating spreadsheets or Facility Rating database to
show that they used the calculated circuit capability as the Facility Rating of the circuit and
evidence such as dated correspondence that the resulting Facility Rating was agreed to by its
associated Planning Coordinator, Transmission Operator, and Reliability Coordinator. (R2R3)

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
M4. The Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 2 shall have evidence such as dated
correspondence to show that they provided its Planning Coordinator shall have a documented
process for the determination of , Transmission Operator, and Reliability Coordinator with a
list of facilities as described in R3. associated with those transmission line relays. (R4)
M5. The Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided a list of the facilities associated with those relays to its
Regional Entity. (R5)
M3.M6. The Planning Coordinator shall have a current list of such facilities and shall have
evidence such as power flow results, calculation summaries, or study reports that it
providedthey used the list to criteria established within Attachment B to determine the
approriatefacilities that must comply with this standard as described in Requirement R6. The
Planning Coordinator shall have a dated list of such facilities and shall have evidence such as
dated correspondence that it provided the list to the Regional Entities, Reliability Coordinators,
Transmission OperatorsOwners, Generator OperatorsOwners, and Distribution Providers. (R3)
within its Planning Coordinator Area.
M7. The Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as dated spreadsheets, summaries of calculations, and study reports, that it implemented
the Requirements within the specified timeframe per Requirement R7.
D. Compliance
1.

Compliance Monitoring Process
3.1.1.1.
3.1.1

Compliance Monitoring Responsibility
Compliance Enforcement Authority

3.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
Regional Entity
3.3.1.2.

Data Retention

The Transmission Owner, Generator Owner, Distribution Provider and Planning Coordinator
shall keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation to demonstrate compliance with Requirements R1 through R5 and R7 for
three calendar years.
The Planning Coordinator shall retain documentation of the most recent review process
required in R3R6. The Planning Coordinator shall retain the most recent list of facilities that
are critical to the reliability of the electric system determined per R3R6.
If a Transmission Owner, Generator Owner, Distribution Provider or Planning Coordinator is
found non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time specified above, whichever is longer.
The Compliance Monitor shall retain its compliance documentation for three yearskeep the
last audit record and all requested and submitted subsequent audit records.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

3.4.1.4.

Additional Compliance Information

The Transmission Owner, Generator Owner, Planning Coordinator, and Distribution Provider
shall each demonstrate compliance through annual self-certification, or compliance audit
(periodic, as part of targeted monitoring or initiated by complaint or event), as determined by
the Compliance Enforcement Authority.
None.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability

4.2.

Violation Severity Levels:

R#Requirement
R1

Lower
N/A

Moderate
Evidence that relay settings
comply with criteria in R1.1
though 1.13 exists, but
evidence is incomplete or
incorrect for one or more of the
subrequirements. N/A

High
N/A

Severe
Relay settings do not comply
with any of the sub
requirements R1.1 through
R1.13
OR
Evidence does not exist to
support that relay settings
comply with one of the criteria
in subrequirements R1.1
through R1.13.The responsible
entity did not use any one of the
following criteria (Requirement
R1 criterion 1 through 13) for any
specific circuit terminal to prevent
its phase protective relay settings
from limiting transmission system
loadability while maintaining
reliable protection of the Bulk
Electric System for all fault
conditions.
OR
The responsible entity did not
evaluate relay loadability at 0.85
per unit voltage and a power
factor angle of 30 degrees.

N/A

Draft 2: November 1, 2010

N/A

The responsible entity failed to
ensure that its out-of-step
blocking elements allowed
tripping of phase protective relays
for faults that occur during the
loading conditions used to verify
transmission line relay loadability

Standard PRC-023-1 2 — Transmission Relay Loadability
per Requirement R1.
R2R3

Criteria described in R1.6,
R1.7. R1.8. R1.9, R1.12, or
R.13 was used but evidence
does not exist that agreement
was obtained in accordance
with R2.N/A

N/A

The responsible entity that uses a
circuit capability with the
practical limitations described in
Requirement R1 criterion 6, 7, 8,
9, 12, or 13 did not use the
calculated circuit capability as the
Facility Rating of the circuit.
OR
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, Regional
Entity, and Reliability
Coordinator with a list of facilities
that have transmission line relays
set according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

R3R6

N/A

ProvidedThe Planning
Coordinator used the criteria

Does not have a process in
place to determine facilities

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
established within Attachment B
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met parts 6.3
through 6.5, but more than 15
months and less than 24 months
lapsed between assessments.
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met 6.3 and 6.5 but
failed to include the year studied
for which criterion B4 in
Attachment B first applies when a
facility is added and only criterion
B4 is applicable (part 6.4).
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met 6.3 and 6.4 but
provided the list of facilities
critical to the reliability of the

Draft 2: November 1, 2010

established within Attachment B
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met parts 6.3
through 6.5, but 24 months or
more lapsed between assessments.

that are critical to the reliability
of the Bulk Electric System.
The Planning Coordinator failed
to use the criteria established
within Attachment B to determine
which transmission Elements,
described in 6.1 and 6.2, in its
Planning Coordinator area must
comply with the standard.

The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met 6.3 and 6.4 but
provided the list of facilities
critical to the reliability of the
Bulk Electric System to the
appropriateto the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers
betweenwithin its Planning
Coordinator Area within 46 days
and 60 days after list was
(part
established or updated.
6.5).

Does not maintain a current list
of facilities critical to the
reliability of the Bulk Electric
System,
OR
Did notThe Planning Coordinator
used the criteria established
within Attachment B, at least once
each calendar year, with no more
than 15 months between
assessments, to determine which
transmission Elements, described
in 6.1 and 6.2, in its Planning
Coordinator area must comply
with the standard but failed to
meet parts 6.3, 6.4 and 6.5.
OR
The Planning Coordinator used
the criteria established within
Attachment B, at least once each
calendar year, with no more than
15 months between assessments,
to determine which transmission
Elements in its Planning
Coordinator area must comply
with the standard but failed to
apply the criteria to the Elements

Standard PRC-023-1 2 — Transmission Relay Loadability
Bulk Electric System to the
appropriateto the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers between
31 dayswithin its Planning
Coordinator Area within 31days
and 45 days after the list was
established or updated. (part 6.5).

described in parts 6.1 and 6.2.
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met 6.4 and 6.5 but
failed to maintain the list of
facilities determined according to
the process described in
Requirement R6 (part 6.3).
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine which transmission
Elements, described in 6.1 and
6.2, in its Planning Coordinator
area must comply with the
standard and met 6.3 and 6.4 but
failed to provide the list of
facilities critical to the reliability
of the Bulk Electric System to
the appropriateto the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers, within its
Planning Coordinator Area or
provided the list more than 60
days after the list was established
or updated. (part 6.5).

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
R7

N/A

Draft 2: November 1, 2010

N/A

The Transmission Owner,
Generator Owner, or Distribution
Provider failed to implement
Requirement R1, Requirement
R2, Requirement R3,
Requirement R4, and
Requirement R5 for each facility
that is added to the Planning
Coordinator’s list of facilities that
must comply with this standard
pursuant to Requirement R6, Part
6.5 by the later of the first day of
the second calendar quarter after
24 months following notification
by the Planning Coordinator of a
facility’s inclusion on such a list
by the Planning Coordinator or
the first day of the first calendar
quarter of the year in which
Attachment B criterion B4 first
applies.

Standard PRC-023-1 2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1.3.

The following document is an explanatory supplement to the standard. It provides the
technical rationale underlying the requirements in this standard. The reference document
contains methodology examples for illustration purposes it does not preclude other technically
comparable methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.

Version History
Version

Date

Action

Change Tracking

February 12,
2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe
VSL for Requirement 3 — “then” should be
“than.”

Errata

March 18, 2010

Approved by FERC

November 1, 2010

Revised to address directives from Order 733

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
PRC-023 — Attachment A
R1.1. This standard includes any protective functions which could trip with or without time delay, on
load current, including but not limited to:
4.1.1.1.

Phase distance.

4.2.1.2.

Out-of-step tripping.

4.3.1.3.

Switch-on-to-fault.

4.4.1.4.

Overcurrent relays.

4.5.1.5.

Communications aided protection schemes including but not limited to:
4.5.11.5.1 Permissive overreach transfer trip (POTT).
4.5.21.5.2 Permissive under-reach transfer trip (PUTT).
4.5.31.5.3 Directional comparison blocking (DCB).
4.5.41.5.4 Directional comparison unblocking (DCUB).

This standard includes out-of-step blocking schemes which shall be
evaluated to ensure that they do not block trip for faults during the
loading conditions defined within the requirements.

FERC Order 733, ¶264: Revise
section 1 of Attachment A to
include supervising relay
elements.

1.6. Supervisory elements associated with current-based,
communication-assisted schemes where the scheme is capable of tripping for loss of
communications.
R2.2.

The following protection systems are excluded from requirements of this standard:

5.1.2.1.
Relay elements that are only enabled when other relays or associated systems fail. For
example:
1.3.1• Overcurrent elements that are only enabled during loss of potential conditions.
1.3.2• Elements that are only enabled during a loss of communications. except as noted
in section 1.6
5.2.2.2.

Protection systems intended for the detection of ground fault conditions.

5.3.2.3.

Protection systems intended for protection during stable power swings.

5.4.2.4.

Generator protection relays that are susceptible to load.

5.5.2.5.
Relay elements used only for Special Protection Systems applied and approved in
accordance with NERC Reliability Standards PRC-012 through PRC-017 or their successors.
5.6.2.6.
Protection systems that are designed only to respond in time periods which allow
operators 15 minutes or greater to respond to overload conditions.
5.7.2.7.

Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.

5.8.2.8.

Relay elements associated with DCdc lines.

5.9.2.9.

Relay elements associated with DCdc converter transformers.

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
PRC-023 — Attachment B
Criteria
Review each applicable circuit against the criteria in this Attachment to
determine the facilities that must comply with the standard.
Applicable circuits include:

•
•

FERC Order 733, ¶69: Specify
the test that PC’s must use to
determine whether sub-200 kV
facility is critical to reliability of
the BES

•

When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.

•

Draft 2: November 1, 2010

Standard PRC-023-1 2 — Transmission Relay Loadability
b. If the Facility Rating is based on a loading duration greater than four and up to and
including eight hours, the circuit must comply with the standard if the loading exceeds
120% of the Facility Rating.
c. If the Facility Rating is based on a loading duration of greater than eight hours, the circuit
must comply with the standard if the loading exceeds 130% of the Facility Rating.
•

Radial circuits serving only load are excluded.

•B5.
Each circuit that the Planning Coordinator may include based on other technical studies
or assessments.

Draft 2: November 1, 2010

Standard Authorization Request Form
Title of Proposed Standard

Relay Loadability Order 733

Request Date

8/5/2010

SC Approval Date

8/12/2010

Revised Date

11/1/2010

SAR Requester Information
Name

SAR Type (Check a box for each one
that applies.)

Stephanie Monzon

New Standard

Primary Contact
Stephanie.monzon@nerc.net

Revision to existing Standard

Telephone

610-608-8084

Withdrawal of existing Standard

Stephanie.monzon@nerc.net

Urgent Action

Fax
E-mail

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Standards Authorization Request Form

Detailed Description
Phase I: Develop modifications to PRC-023-1- Transmission Relay Loadability by March 18,
2011 to address the following directives from Order 733:
•

•

p 162 . . . consider “islanding” strategies that achieve the fundamental performance for
all islands in developing the new Reliability Standard addressing stable power swings.

•

p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.

•

p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]

•

p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.

•

p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the Reliability
Standard.

•

p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.

•

p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.

Standards Authorization Request Form

•

p. 108 . . . consider the PSEG Companies’ suggestion in developing a Reliability
Standard that addresses generator relay loadability.

As indicated in NERC’s Order No. 733 clarification and rehearing request, NERC believes
adding additional requirements to the PRC-023 standard in addition to developing a new
Reliability Standard to address generator relay loadability could lead to confusion over
applicability and the possibility of conflicting requirements. Therefore, NERC proposed in its
clarification and rehearing request to address the issue of generator relay loadability in a
new Reliability Standard, separate and distinct from the PRC-023 Reliability Standard, which
is intended to address relays that protect transmission elements. Subject to the
Commission’s response to NERC’s pending clarification and rehearing request, NERC plans
to address generator relay loadability in a new Reliability Standard for applications where
the relays are set with a shorter reach to protect the generator and the generator step-up
transformer, and for applications where the relays are set with a longer reach to provide
backup protection for transmission system faults. The standard drafting team will use
relevant sections of the NERC technical reference document, Power Plant and Transmission
System Protection Coordination Section 3.1 and Appendix E to develop the requirements by
which generator relay loadability will be assessed.
Phase III: Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings
In Phase III of the project, a new Reliability Standard will be developed to address the
subject of protective relay operations due to power swings to address the following directive
from Order No. 733 by the end of 2014:
•

SAR–4

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–5

Standards Authorization Request Form

SAR–6

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

PRC-023-1

New Reliability
Standard

Development of a New Standard Addressing Generator Relay Loadability

New Reliability
Standard

Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC

SAR–7

Paragraph

Text

Project Phase/
Timeline

With respect to sub-100 kV facilities, we adopt the NOPR proposal and direct
the ERO to modify PRC-023-1 to apply an “add in” approach to sub-100 kV
facilities that are owned or operated by currently-Registered Entities or entities
that become Registered Entities in the future, and are associated with a facility
that is included on a critical facilities list defined by the Regional Entity. We
also direct that additions to the Regional Entities’ critical facility list be tested
for their applicability to PRC-023-1 and made subject to the Reliability
Standard as appropriate.

Phase I -- by
March 18, 2011

Phase I -- Note
NERC’s pending
request for
rehearing filed on
April 19, 2010
regarding this
directive.

Finally, commenters argue that there should be some mechanism for entities to
challenge criticality determinations. We agree that such a mechanism is
appropriate and direct the ERO to develop an appeals process (or point to a
process in its existing procedures) and submit it to the Commission no later
than one year after the date of this Final Rule.

Phase I – by
March 18, 2011

105

Phase II – by the
end of 2012

108

Phase II – by the
end of 2012

150

Phase III – by the
end of 2014

Attachment 1 - Order No. 733 – Action Plan and Timetable

Paragraph

Text

Project Phase/
Timeline

Phase I – by
March 18, 2011

186

Phase I – by
March 18, 2011

203

Phase I – by
March 18, 2011

224

While we are not adopting the NOPR proposal, we direct the ERO to
document, subject to audit by the Commission, and to make available for
review to users, owners and operators of the Bulk-Power System, by request, a
list of those facilities that have protective relays set pursuant sub-requirement
R1.12.

Phase I – by
March 18, 2011

237

We adopt the NOPR proposal and direct the ERO to modify the Reliability
Standard to add the Regional Entity to the list of entities that receive the
critical facilities list. [sub-requirement R3.3]

Phase I – by
March 18, 2011

244

We adopt the NOPR proposal and direct the ERO to include section 2 of
Attachment A in the modified Reliability Standard as an additional
Requirement with the appropriate violation risk factor and violation severity
level.

Phase I – by
March 18, 2011

264

Phase I – by
March 18, 2011

283

Additionally, in light of our directive to the ERO to expand the Reliability
Standard’s scope to include sub-100 kV facilities that Regional Entities have
already identified as necessary to the reliability of the Bulk-Power System
through inclusion in the Compliance Registry, we direct the ERO to modify the
Reliability Standard to include an implementation plan for sub-100 kV
facilities.

Phase I – by
March 18, 2011

Attachment 1 - Order No. 733 – Action Plan and Timetable

Paragraph

Text

Project Phase/
Timeline

284

We also direct the ERO to remove the exceptions footnote from the “Effective
Dates” section.

Phase I – by
March 18, 2011

297

Finally, we direct the ERO to assign a “high” violation risk factor to
Requirement R3.

Filed with the
Commission on
April 19, 2010

308

Consequently, we direct the ERO to assign a single violation severity level of
“severe” for violations of Requirement R1.

Filed with the
Commission on
April 19, 2010

310

Accordingly, we direct the ERO to change the violation severity level assigned
to Requirement R2 from “lower” to “severe” to be consistent with Guideline
2a.

Filed with the
Commission on
April 19, 2010

311

Finally, we direct the ERO to assign a “severe” violation severity level to
Requirement R3.

Filed with the
Commission on
April 19, 2010

Standard Authorization Request Form
Title of Proposed Standard

Relay Loadability Order 733

Request Date

8/5/2010

SC Approval Date

8/12/2010

Revised Date

11/1/2010

SAR Requester Information
Name

SAR Type (Check a box for each one
that applies.)

Stephanie Monzon

New Standard

Primary Contact
Stephanie.monzon@nerc.net

Revision to existing Standard

Telephone

610-608-8084

Withdrawal of existing Standard

Stephanie.monzon@nerc.net

Urgent Action

Fax
E-mail

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Standards Authorization Request Form

Detailed Description
Phase I: Develop modifications to PRC-023-1- Transmission Relay Loadability by March 18,
2011 to address the following directives from Order 733:
•

•

p 162 . . . consider “islanding” strategies that achieve the fundamental performance for
all islands in developing the new Reliability Standard addressing stable power swings.

•

p. 186 . . . require that transmission owners, generator owners, and distribution
providers give their transmission operators a list of transmission facilities that implement
sub-requirement R1.2.

•

p. 237 . . . modify the Reliability Standard to add the Regional Entity to the list of
entities that receive the critical facilities list. [sub-requirement R3.3]

•

p. 244 . . . include section 2 of Attachment A in the modified Reliability Standard as an
additional Requirement with the appropriate violation risk factor and violation severity
level.

•

p. 264 . . . revise section 1 of Attachment A to include supervising relay elements on the
list of relays and protection systems that are specifically subject to the Reliability
Standard.

•

p. 283 . . . modify the Reliability Standard to include an implementation plan for sub100 kV facilities.

•

p. 284 . . . remove the exceptions footnote from the “Effective Dates” section.

Standards Authorization Request Form

•

p. 108 . . . consider the PSEG Companies’ suggestion in developing a Reliability
Standard that addresses generator relay loadability.

SAR–4

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–5

Standards Authorization Request Form

SAR–6

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

PRC-023-1

New Reliability
Standard

Development of a New Standard Addressing Generator Relay Loadability

New Reliability
Standard

Development of a New Standard Addressing the Issue of Protective Relay
Operations Due To Power Swings

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC

SAR–7

Paragraph

Text

Project Phase/
Timeline

With respect to sub-100 kV facilities, we adopt the NOPR proposal and direct
the ERO to modify PRC-023-1 to apply an “add in” approach to sub-100 kV
facilities that are owned or operated by currently-Registered Entities or entities
that become Registered Entities in the future, and are associated with a facility
that is included on a critical facilities list defined by the Regional Entity. We
also direct that additions to the Regional Entities’ critical facility list be tested
for their applicability to PRC-023-1 and made subject to the Reliability
Standard as appropriate.

Phase I -- by
March 18, 2011

Phase I -- Note
NERC’s pending
request for
rehearing filed on
April 19, 2010
regarding this
directive.

Finally, commenters argue that there should be some mechanism for entities to
challenge criticality determinations. We agree that such a mechanism is
appropriate and direct the ERO to develop an appeals process (or point to a
process in its existing procedures) and submit it to the Commission no later
than one year after the date of this Final Rule.

Phase I – by
March 18, 2011

105

Phase II – by the
end of 2012

108

Phase II – by the
end of 2012

150

Phase III – by the
end of 2014

Attachment 1 - Order No. 733 – Action Plan and Timetable

Paragraph

Text

Project Phase/
Timeline

Phase I – by
March 18, 2011

186

Phase I – by
March 18, 2011

203

Phase I – by
March 18, 2011

224

While we are not adopting the NOPR proposal, we direct the ERO to
document, subject to audit by the Commission, and to make available for
review to users, owners and operators of the Bulk-Power System, by request, a
list of those facilities that have protective relays set pursuant sub-requirement
R1.12.

Phase I – by
March 18, 2011

237

We adopt the NOPR proposal and direct the ERO to modify the Reliability
Standard to add the Regional Entity to the list of entities that receive the
critical facilities list. [sub-requirement R3.3]

Phase I – by
March 18, 2011

244

We adopt the NOPR proposal and direct the ERO to include section 2 of
Attachment A in the modified Reliability Standard as an additional
Requirement with the appropriate violation risk factor and violation severity
level.

Phase I – by
March 18, 2011

264

Phase I – by
March 18, 2011

283

Additionally, in light of our directive to the ERO to expand the Reliability
Standard’s scope to include sub-100 kV facilities that Regional Entities have
already identified as necessary to the reliability of the Bulk-Power System
through inclusion in the Compliance Registry, we direct the ERO to modify the
Reliability Standard to include an implementation plan for sub-100 kV
facilities.

Phase I – by
March 18, 2011

Attachment 1 - Order No. 733 – Action Plan and Timetable

Paragraph

Text

Project Phase/
Timeline

284

We also direct the ERO to remove the exceptions footnote from the “Effective
Dates” section.

Phase I – by
March 18, 2011

297

Finally, we direct the ERO to assign a “high” violation risk factor to
Requirement R3.

Filed with the
Commission on
April 19, 2010

308

Consequently, we direct the ERO to assign a single violation severity level of
“severe” for violations of Requirement R1.

Filed with the
Commission on
April 19, 2010

310

Accordingly, we direct the ERO to change the violation severity level assigned
to Requirement R2 from “lower” to “severe” to be consistent with Guideline
2a.

Filed with the
Commission on
April 19, 2010

311

Finally, we direct the ERO to assign a “severe” violation severity level to
Requirement R3.

Filed with the
Commission on
April 19, 2010

Standards Announcement
Ballot Pool Open November 1 – December 2, 2010
Comment Period Open November 1 – December 16, 2010
Now available at: http://www.nerc.com/filez/standards/SAR_Project%202010-

13_Order%20733%20Relay%20Modifiations.html
Project 2010-13: Revisions to Relay Loadability for Order 733
PRC-023-2 – Transmission Relay Loadability has been posted for a 45-day formal comment period, and a ballot
pool is being formed during the first 30 days of the 45-day comment period.
Ballot Pool Open through 8 a.m. on December 2, 2010
A ballot pool is being formed during the first 30 days of the 45-day formal comment period, and an initial ballot will
be conducted during the last 10 days of this comment period.
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballot at the
following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of the ballot pool may communicate with one another by using their “ballot
pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot pool list
servers.) The list server for this ballot pool is: bp-2010-13_Rev RLO 733_in

Formal 45-day Comment Period Open through 8 p.m. on December 16, 2010
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment form is
posted on the project page:
http://www.nerc.com/filez/standards/SAR_Project%202010-13_Order%20733%20Relay%20Modifiations.html
Next Steps
An initial ballot will be conducted during the last 10 days of the 45-day formal comment period. The drafting team
will consider all comments (those submitted with a comment form, and those submitted with a ballot) and will
determine whether to make additional changes to the standard. The team will post its response to comments and, if
the standard has only minor changes, will post the standard and conduct a 10-day recirculation ballot.
Project Background
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it directed several
changes to that standard and also directed development of one or more new standards within specified time periods.
NERC filed for clarification and rehearing asking for clarity and an extension of time to address the directives;
however, without a response to the requests for clarification and rehearing, NERC must progress as though these
requests will be denied.
The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases. Phase I

Applicability of Proposed PRC-023-2
Distribution Providers that own specific facilities (see standard for details)
Generator Owners that own specific facilities (see standard for details)
Planning Coordinators
Transmission Owners that own specific facilities (see standard for details)
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Individual or group. (38 Responses)
Name (25 Responses)
Organization (25 Responses)
Group Name (13 Responses)
Lead Contact (13 Responses)
Question 1 (35 Responses)
Question 1 Comments (38 Responses)
Question 2 (33 Responses)
Question 2 Comments (38 Responses)
Question 3 (37 Responses)
Question 3 Comments (38 Responses)
Question 4 (37 Responses)
Question 4 Comments (38 Responses)
Question 5 (35 Responses)
Question 5 Comments (38 Responses)
Question 6 (37 Responses)
Question 6 Comments (38 Responses)
Question 7 (35 Responses)
Question 7 Comments (38 Responses)
Question 8 (36 Responses)
Question 8 Comments (38 Responses)
Individual
Joe Petaski
Manitoba Hydro
Yes
Yes
Yes
Yes
No
1. We don’t think that the system would change that fast to warrant the additional work of conducting an assessment every
year. The entities involved have 24 months to make the necessary changes as given in R7. If an annual assessment is
required then this should be added as a requirement to TPL-001-2 rather than buried in PRC-023. It would be more
efficient to perform an assessment over the 10-year planning horizon every 2-3 years. Critical facilities identified in the
assessment can be monitored in the in-between years to ensure construction schedules are on track and the need is still
there. One initial detailed assessment of the current year facilities could be done but then the assessment should be more
focused on additions and changes. 2. The VSLs for R6 are too severe. The system doesn’t change that rapidly and getting
the list to the entities involved before 60 days does not impact reliability given that they have 2 years to comply with
changes.
No
The effective date should not be a uniform date, it should be dependent on the number of circuits that have been identified
and determined as critical circuits for an individual utility.
No
Effectively, there is no substantial difference between the protection elements described in section 1.6 and the protection
elements described on second bullet in Section 2.1. Why should the protection elements in section 1.6 be included?
During loss of communication, the supervisory elements associated with current based, communication-assisted schemes
(such as line current differential scheme and phase comparison scheme) may be the only protection elements to provide
high speed protection which may be necessary from system reliability perspective. As a result, these supervisory elements
should be set low enough to ensure that they can detect all fault condition. Since these supervisory elements are only in
effect under loss of communication contingency, I don’t think they should be subjected to the same requirements as those
load responsive elements under normal condition. They should be treated the same as those elements described on the
first bullet in section 2.1.
No
In attachment B and the standard, there’s discussion of 15 min., up to 4 hour, 4-8 hour and more than 8 hour ratings. This
is very prescriptive and doesn’t match the requirements in the Facility rating methodology standard or the model building
limitations. It seems there is a disconnect between the FAC, TPL and PRC standards.
Group
Electric Market Policy

Mike Garton
Yes
Yes
Yes
Yes
Yes
Yes
Yes
5.1 Requirement R1. Dominion would like to see the exception of "switch on to fault" schemes added back in.
Individual
Mace Hunter
Lakeland Electric
Yes
Yes
Yes
Yes
No
In R6.2 the phrase “for the purposes of the Compliance Registry and” is used. The same phrase is also used under
Applicability in sections 4.2.3 and 4.2.6. What is the purpose of this phrase in these sections? I do not think that the
phrase has any value in these locations. The phrase is also used in the PRC-023 – Attachment B in the second bullet
under “Criteria”. It seems to imply that if a circuit is identified as a critical facility that fact could be used to drive registration
of an entity that otherwise may not require registration. If that is the intent then I would suggest modifying the phrase in the
attachment to “that may require entity registration in the Compliance Registry “
Yes
Yes
Yes
Group
Potomac Holdings Inc & Affiliates
David K Thorne
Yes
Please note that a typographical error exists in Requirement R1 Criterion 9. The sentence should end with the phrase
“flow from the load to the system under any system configuration”. The words load and system have been inadvertently
omitted in both this draft and the previous draft.
Yes
Yes
In the SDT’s response “Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set
of proposed requirements – Project 2010-13” dated November 1, 2010, the SDT proposed to establish the effective date
for requirements R4 & R5 as “the first day of the first calendar quarter following 24 months after regulatory approvals.”
However in the latest draft of the standard the 24 month requirement was replaced with 6 months. Which is correct?
Yes
In the SDT’s response “Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and an initial set
of proposed requirements – Project 2010-13” dated November 1, 2010, the SDT proposed to establish the effective date
for requirements R4 & R5 as “the first day of the first calendar quarter following 24 months after regulatory approvals.”
However in the latest draft of the standard the 24 month requirement was replaced with 6 months. Which is correct?
Yes

Yes
No
The current wording of section 1.6 is a significant improvement over the previous version. The intent of this section was to
specifically address phase overcurrent supervising elements (i.e. phase fault detectors) associated with pilot wire, phase
comparison, and line current differential schemes where the scheme is capable of tripping for loss of communications.
However, we believe that the term “current-based communication-assisted schemes” is too generic and may be confusing
without mention of the specific schemes to which this requirement applies. Also, only phase overcurrent supervising
elements are in scope, not ground overcurrent supervising elements. Therefore, to clarify the requirement we suggest
replacing the current wording with either “Phase overcurrent supervisory elements (i.e. phase fault detectors) associated
with pilot wire, phase comparison, and line current differential schemes, where the scheme is capable of tripping for loss of
communications” or “Phase overcurrent supervisory elements (i.e. phase fault detectors) associated with current-based
communication-assisted schemes (i.e. pilot wire, phase comparison, and line current differential) where the scheme is
capable of tripping for loss of communications”.
Yes
Individual
Joe O'Brien for Tom Nappi
NIPSCO
No
The mechanical withstand is not an appropriate value because every fault event will reduce the life of a transformer.
Setting the limit at the maximum expected one time event limit will prematurely destroy the transformers. Maybe a sliding
scale would be better with each transfromer owner to decided how much expected life to risk for faults.
No
We believe this is already included
No
We're not sure what the value is in this requirement?
No
We believe the R1 criterion 12 is needed- but the reporting requirment is not.
No
Only the owner or TO GO DP should apply the criteria – which can be then reported to the PC
No
We believe only the owners of facilities should have this requirment, not the PC
No
Don’t know what is referred to here except maybe a current differential scheme. There is no need for this added
requirement.
Yes
The method seems OK but the standard requirement R1 should be changed because lower voltage lines have far more
resistance and arc resistance needs to be included. General Comments: We think that the proposed revised standard
incorrectly assigns responsibility to the PC instead of the TO,GO DP Also, the new standard forces compliance on lower
voltage lines which would limit protection of equipment which will ultimately lead to many fewer networked lines and a less
reliable electric system.
Individual
Nicholas Klemm
Western Area Power Administration
No
Established industry standards and practices have defined the mechanical damage portion of the transformer curve to
apply for repetitive faults. Neither FERC nor NERC should have the right to contradict established technical practices.
Entities should be able to coordination protection systems taking into account protection and controls (e.g. the use of
lockouts) which prevent repetitive exposure to mechanical damage thereby alleviating cumulative effects. Also, it is not
clear what "transmission line relays on transmission lines terminated only with a transformer..." applies to. Need
clarification.
Yes
Yes
Yes
No
Feel that NERC is delving too much into the technical details. Should allow Planning Coordinators to establish their own
study methodologies.
Yes

No
Both the FERC order and section 1.6 are unclear.
No
Is this necessary? Allow Planning Coordinators to do their jobs and decide which circuits are important.
Individual
Richard Burt
Minnkota Power Cooperative, Inc.
Yes
Yes
Yes
Yes
No
Many facilities with voltages between 100kV and 200kV will only impact a well-defined local load region if they trip. There
is no risk of cascading outages beyond the local load region. The criteria in Attachment B should allow these types of
facilites to be dismissed from evaluation.
Yes
Yes
No
Many facilities with voltages between 100 kV and 200 kV will only impact a well-defined local load region if they trip. There
is no risk of cascading outages beyond the local load region. The criteria in Attachment B should allow these facilities to
be dismissed from further evaluation.
Group
Northeast Power Coordinating Council
Guy Zito
No
Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection to protect from
mechanical damage, either from internal faults, or through faults. If load responsive protection for the transformer element
does not presently exist, i.e. only differential protection exists for the transformer element, will load responsive transformer
protection have to be added to comply with this criterion? The wording in criterion 10 should be changed to “Set
transformer fault protection relays or transmission line relays on transmission lines terminated only with a transformer to
…….” Is this criteria requiring that a transformer with only differential protection and no other load responsive remote
protection be supplemented additional load responsive protection? The loading on phase angle regulators, and series
reactors should be considered and mentioned. Also, there appears to be words missing in criterion 9 of R1: “the maximum
current flow from the ? to the ? under any system configuration.” From the NERC Webinar on 11/23/10 the intention was
to address the possible locations where phase protection for the transformer could exist and not imply that this protection
was needed at both locations.
Yes
Yes
Yes
Yes
Yes
Yes
No
B2. Item B2 adds significant confusion to the process. The long term planning horizon may include transmission projects
which have not even been built or alternative system configurations which do not exist, making it impossible for affected
parties to set their relays appropriately. Suggested replacement language to avoid this issue: “Each circuit that is a
monitored element of an IROL, assuming that all transmission elements are in service and the system is under normal
conditions.” B3. This item indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement by the plant and
the Transmission Entity it should be removed from Attachment B and placed elsewhere in the document. If this is intended
to apply to the Planning Coordinator, Transmission Entity should be replaced with Planning Coordinator. Why does B3

only apply to Nuclear Power Plants? B4. This criterion is overly stringent and should be deleted. The system is neither
planned nor operated to allow for two overlapping outages without operator action in between. If this criterion is retained, it
should be made consistent with the requirements of TPL-003 where operator actions can be assumed between the first
and second contingencies. Since a similar comment was made previously, more information is being provided following. 1.
Since the system is neither planned nor operated to two overlapping outages in between, such testing may result in
unsolved cases, or voltages well below criteria. In the case of an unsolved case, there are no flows to evaluate, making
this standard impossible to apply. In the case of a solved case with voltages well below criteria, currents are likely to be
incredibly high and therefore viewed as unrealistic. These concerns may limit the contingency selection to those which are
not severe, eliminating any perceived benefit from this testing. 2. There is no guidance provided on how the system should
be dispatched in the model upon which the overlapping contingencies are tested. This will result in significant
discrepancies between the base assumptions used by the various Planning Coordinators. The contents of this standard
should be reviewed to reflect the new definition of the Bulk Electric System.
Individual
Kathleen Goodman
ISO New England Inc.

No
B2. Item B2 adds significant confusion to the process. The long term planning horizon may include transmission projects
which have not even been built or alternative system configurations which do not exist, making it impossible for affected
parties to set their relays appropriately. Suggested replacement language to avoid this issue: “Each circuit that is a
monitored element of an IROL, assuming that all transmission elements are in service and the system is under normal
conditions.” B3. This item indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement by the plant and
the Transmission Entity it should be removed from Attachment B and placed elsewhere in the document. If this is intended
to apply to the Planning Coordinator, Transmission Entity should be replaced with Planning Coordinator. B4. This criterion
is overly stringent and should be deleted. The system is neither planned nor operated to allow for two overlapping outages
without operator action in between. If this criterion is retained, it should be made consistent with the requirements of TPL003 where operator actions can be assumed between the first and second contingencies. Since a similar comment was
made previously, more information is being provided in this set of comments. 1. Since the system is neither planned nor
operated to two overlapping outages in between, such testing may result in unsolved cases, or voltages well below
criteria. In the case of an unsolved case, there are no flows to evaluate, making this standard impossible to apply. In the
case of a solved case with voltages well below criteria, currents are likely to be incredibly high and therefore viewed as
unrealistic. These concerns may limit the contingency selection to those which are not severe, eliminating any perceived
benefit from this testing. 2. There is no guidance provided on how the system should be dispatched in the model upon
which the overlapping contingencies are tested. This will result in significant discrepancies between the base assumptions
used by the various Planning Coordinators.
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
No
The comment group finds R1.10 very confusing when attempting to understand it in the context of IEEE C57.109-1993.
C57.109 identifies a solid curve as the thermal damage curve, while a dotted dog leg is the mechanical damage curve.
Generally the dog leg is only considered for those class II and III transformers subjected to frequent through faults and all
class IV transformers. Is the intent of the SDT to require this level of protection for all transformers regardless of through
fault frequency and/or transformer class? If the SDT really meant to protect transformers from thermal or combination
damage, please note that it is not possible to completely protect transformers from the thermal damage of low current long
duration faults while still complying with the 150% of maximum rating. The thermal damage curve extends down to twice
the base current. A footnote in C57.109 states that base current is established from the lowest nameplate kVA rating. A
typical transformer with two stages of cooling will have a high nameplate rating of 1.67 times this base rating. The first
bullet of R1.10 states affected entities must allow 1.5 times the maximum, so we are up to 2.5 times the base rating. Since
we must allow this much without tripping, the relay must be set even higher. 1.2 times would be a secure margin, so the
relay is set to pickup at 3 times the base rating. This setting would of course violate the first part of R1 criterion 10
because the transformer’s fault capability would be exceeded for faults between 2 and 3 times the base rating. We also
note that criterion 11 is apparently an exception to criterion 10, but this is not altogether clear since 10 is for fault
protection while 11 is for overload protection. Please rewrite this (these) criterion (criteria) to clarify the SDT’s intent(s).
Yes
Yes
No
The FERC Order 773 page 224 states that this information is to be made available to the entities “by request.” Unless a
request happens to coincide with the annual submittal, this order is not being addressed. There is also no requirement that

the Regional Entity make the lists available to the other entities as ordered. We don’t believe the intent of the order was
achieved in R5.
Yes
Yes
Yes
No
We thank the SDT for addressing our concern regarding radially operated circuits. We note, however, that the key word
“operated” from the consideration of comments was dropped before it reached the standard. Please change the last bullet
of B4 to: "Radially operated circuits serving only load are excluded."
Individual
Greg Rowland
Duke Energy
Yes
Yes
Yes
Yes
No
• R6.1 and R6.2 unnecessarily duplicate the first part of Attachment B, and should be deleted from R6. • R6.3 and R6.4
are both associated with maintaining the list and should be combined into a separate requirement (new R7), with its own
VRF and VSLs. Including the year for a facility should apply to all the criteria, not just B4. Suggested wording for new R7:
“Maintain a list of circuits that must comply with this standard due to meeting Attachment B criteria. For each circuit,
include the applicable criteria and the year studied for which the criteria first applies, when a facility is added to the list.” •
R6.5 should become a new R8 with its own VRF and VSLs. No wording changes needed.
No
Since the Attachment B criteria are applied beyond the operating horizon, R7 should be rewritten (and also renumbered
as R9). Suggested wording: “ Each Transmission Owner, Generator Owner, and Distribution Provider shall implement
Requirement R1, Requirement R2, Requirement R3, Requirement R4, and Requirement R5 for each facility that is added
to the Planning Coordinator’s list of facilities that must comply with this standard pursuant to Requirement R6, by the first
day of the first calendar quarter of the year in which Attachment B criteria first apply. [Violation Risk Factor: High] [Time
Horizon: Long Term Planning]
Yes
No
• B2 needs additional clarification, because identification could be in the short term or long term planning horizon.
Suggested rewording: “B2. Each circuit that is a monitored Element of an IROL where the IROL was determined beyond
the operating horizon.” • B3 needs additional clarification, to explicitly identify the necessary agreement between the plant
owner and Transmission Entity. Suggested rewording: “Each circuit that forms a path (as agreed to by the plant owner and
the Transmission Entity pursuant to NUC-001) to supply off-site power to nuclear plants.
Individual
Tim Hinken
Kansas City Power & Light
Yes
Yes
No
We do not believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission line’s
highest seasonal 15 minute rating does not equate to a line that will trip before the operator has time to intervene. It does
not mean the line will trip in 15 minutes. In fact, the operator should be taking action well in advance of reaching a 15
minute limit and the operator is likely only using the 15 minute rating in extreme circumstances. Furthermore, PRC-023-2
R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC-008-1 and FAC-009-1 already collectively require the
Transmission Owner and Generator Owner to establish a facilities ratings methodology, rate its facilities consistent with its
methodology and to communicate those ratings and methodology to its Planning Coordinator, Reliability Coordinator and
Transmission Operator. More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to
consider relay protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed. We assume the drafting team
must be aware of these FAC standard requirements because they did not even require reporting to the Reliability

Coordinator, Planning Coordinator and Transmission Operator of those circuits that are actually limited by the relay per
criterion 12. We agree that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits and that no additional requirements
are necessary.
No
While we don’t necessarily have an issue with the equipment owner communicating these relay limited circuits to the
Regional Entities, we don’t believe this is needed for reliability and therefore it should not be included in the reliability
standard. Given that it is unclear what the information will even be used for, if it will be needed long-term, and that it is
likely will not change much, if at all, from year to year, we believe a data request through NERC’s Rules of Procedure
section 1600 would be more appropriate. In that way, we don’t have to modify the standard later when NERC and the
Regions determine they don’t need the data annually.
No
It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has identified that are
below 100 kV that are part of the Bulk Electric System. This information is not readily available and there is no requirement
for the Regional Entity to communicate it to them. Thus, inaction by the auditor (i.e. Regional Entity) could actually cause
the Planning Coordinator to violate this requirement. This is clearly a conflict of interest. Why does the Planning
Coordinator need to identify which circuits are identified per criteria B4? There is no justification given for this need and
there is nothing else that appears to require action as a result of this information. Thus, it is purely administrative and
should be removed. Registered entities should never be subject to potential sanctions for violations of purely
administrative portions of requirements. Why does the Planning Coordinator need to provide this information to the
Reliability Coordinator? There is nothing for the Reliability Coordinator to do with the information. The Reliability
Coordinator only needs to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1.
No
We do not believe that R7 is needed. The applicability section of the standard is clear that the standard applies to those
circuits identified in R6. This requirement could be construed as potential for double jeopardy because failure to comply
with Requirements 1-5 for represent a violation of both Requirement 7 and Requirement 1-5.
Yes
No
While we appreciate the drafting team’s effort to refine the flowgate criteria from the last posting, the modifications do not
go far enough and still do not reflect the use of flowgates. NERC’s definition of flowgate includes two components. Let’s
focus on the first component which represents those flowgates defined in the IDC. Because IDC flowgates list is updated
monthly and the IDC users can add temporary flowgates to the IDC at any time, this is an inappropriate list to use. We
appreciate the drafting team’s attempt to resolve this issue by including the caveat “that has been included to address
long-term reliability concerns, as confirmed by the applicable Planning Coordinator.” However, this really only confuses the
matter and does not solve it. Reliability Coordinators add flowgates to manage real-time congestion. Planning
Coordinators do not. Per the NERC functional model, they do not even have a role in deciding which flowgates to add to
the IDC. Flowgates are added to the IDC to mitigate existing, known congestion points not congestion points identified in a
long-term planning study that may never materialize due to changing conditions. Thus, IDC flowgates should be
specifically excluded. Now let us focus on the second component of flowgate. The second component is much like the first
component in that is it a mathematical construct to analyze the impact of power flows on the BES except is not required to
be included in the IDC. There is nothing in the definition of a flowgate to give credence that is represents anything more
that point to calculate power flows and the impact of transactions. Flowgates are primarily used to manage congestion on
the system and to sell transmission system. Because it is convenient to select a group of lines as a proxy to sell
transmission service or manage congestion does not mean that those group of lines represent a reliability issue. Thus, we
do not believe any flowgates should be included in the list. Any true reliability issues can be identified through the TPL
studies and those facilities that do not meet the performance requirements are what should be used. We do not support
criterion B4. It exceeds what is required in the TPL standards and what is required per the reliability directive in Order 729.
The TPL standards allow system operator intervention for category C3 contingencies between the two independent
Category B contingencies. This standard should not exceed those requirements in the TPL standards. Paragraphs 79 and
80 of FERC Order 729 contain the relevant directives regarding the Planning Coordinator test. Paragraph 79 states that
the test “must include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in transmission
planning.” Paragraph 80 states that “the test must be consistent with the general reliability principles embedded in the
existing series of TPL” standards. Thus, exceeding the TPL standards could be argued as deviating from the directive.
The directive is to be consistent not exceed. Exceeding the TPL standards is not consistency. In response to comments
that did not support this criterion during the first posting, the standards drafting team responded with “Testing multiple
element contingencies while accounting for system adjustments between each element outage will not yield any facilities
to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We think the drafting team
missed a basic point about the standard. The issue is not whether the registered entity develops and documents
corrective actions actions plans TPL-003-0a R2 and R3. The issue is if the system as currently designed meets the
performance requirements in TPL-003-0a R1 which allows for operator interventions on Category C3 contingencies. For
those C3 contingencies that don’t currently meet the performance obligations after operator interventions, the subject
facilities would be included PRC-023-2 R6 list of facilities.
Individual
Andrew Pusztai
American Transmission Company
Yes

Yes
Yes
Yes
Yes
Except ATC is recommending the following wording change for Requirement R 6.2 which provides clarification on the
application of the criteria: “Apply the criteria to the following Elements in its Planning Coordinator Area, if any: those
transmission lines operated below 100 kV and those transformers with low voltage terminal connections below 100 kV that
the Regional Entity has identified as critical facilities for the purposes of the Compliance Registry.”
No
ATC believes it is difficult to determine without knowing the full scope of work. Until the Planning criteria can be
determined, the scope is unknown. Assuming not many assets are added, two years would be a more reasonable amount
of time.
Yes
Yes
Group
Tennessee Valley Authority
Joshua Wooten
Yes
Yes
Yes
Yes
No
Per Requirement R6 criterion 2, the Planning Coordinator is better suited to analyze the subsystem and its effect on the
BES than the Regional Entity, so “Regional Entity” should be replaced with “Planning Coordinator”. Please also see
Question 8 comment concerning the use of “flowgate” in Attachment B section B1.
Yes
Yes
No
The NERC Glossary defines a flowgate as: 1.) A portion of the Transmission system through which the Interchange
Distribution Calculator calculates the power flow from Interchange Transactions. 2.) A mathematical construct, comprised
of one or more monitored transmission Facilities and optionally one or more contingency Facilities, used to analyze the
impact of power flows upon the Bulk Electric System. The IDC flowgates change often thus making it difficult to coordinate
those changes with the critical lines list provided by the Planning Coordinator in Attachment B section B1. We assume that
No. 2 above is the definition that the SDT was referring. However, for clarity, we recommend that either the word
“flowgate” be specifically defined in Attachment B or removed.
Individual
David Burke
Orange and Rockland Utilities, Inc.
No
Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection to protect from
mechanical damage. The wording in criterion 10 should be changed to “set transformer fault protection relay or
transmission line relay on transmission line terminated with only a transformer.” Is this criteria requiring that a transformer
with only differential protection and no other load responsive remote protection be mitigated with additional load
responsive protection? The loading on phase angle regulators, and series reactors should also be considered and
mentioned.
No
What is the expectation for verifying that the out-of-step blocking elements allow tripping of phase protection relays for
faults that occur during the loading conditions used to verify transmission line relay loadability? It would be costly and time
consuming to verify this. To comply with this requirement, utilities may have to remove OOS protections all together. This
should be able to be tested during routine trip testing. Between the trip testing procedures, and relay calibrations this
requirement should be satisfied, and easily documented.
Yes

Yes
Yes
Yes
Yes
No
Why does B3 only apply to Nuclear Power Plants only?
Group
Tri-State G & T System Protection
Bill Middaugh
No
There can be cases where the transformer withstand capability will be exceeded if 150% of the applicable maximum
transformer rating is used for the pickup of overcurrent relays. The requirement cannot then be met if no transformer
emergency rating is established. Modify to indicate that if the loading requirement violates the protection requirement, then
the protection requirement should be used while allowing the maximum loading possible without violating the protection
requirement.
Yes
No
We believe that the list of facilities with transmission line relays that use Requirement R1 criterion 2 needs to be given only
to the Transmission Operators as directed by Paragraph 186 of FERC Order no. 733, and not also to the Planning
Coordinators and Reliability Coordinators. We also believe that an initial submittal is sufficient until any responsible entity
begins or stops using that criterion on any element. Periodic duplicate submittals are unnecessary and unique submittals
would more easily identify the loadability issues that the operators need to consider. The FERC Order did not require
annual submittals.
No
Paragraph 224 of FERC Order no. 733 requires that the ERO document and have available upon request the list of
facilities that use this criterion. The proposed standard is not applicable to the Regional Entity so there is no method to
require the RE to provide the data to the ERO. That seems to indicate that the data should be provided to the ERO rather
than the Regional Entity. We also believe that an initial submittal is sufficient until any responsible entity begins or stops
using that criterion on any element. Periodic duplicate submittals are unnecessary and unique submittals would more
easily identify the loadability issues that the operators need to consider. The FERC Order did not require annual
submittals.
Yes
Yes
Yes
Yes
While we agree that it is a technically sound approach, we have concerns that the criterion B4 is over-burdensome.
Paragraph 82 of FERC Order 733 indicates that the existing TPL simulations and assessments should be a component of
the test. By excluding manual intervention in the assessments the Attachment is expanding the scope beyond the
Commission’s Order. We think there should be a test based on the existing assessments required by the TPL standards
that would then trigger a subsequent test with no manual intervention. An example would be if an element’s loading
exceeded 100% of its Facility Rating using the normal assessment, then the assessment with no manual intervention
would be applied and subsequent steps of criterion B4 would be followed. We think that criterion B5 is too vague, may be
discriminatory, is unnecessary, and should be removed. There is very little basis listed for this criterion above and beyond
those listed in criterion B4, the criterion may be applied discriminatorily or differently even within the same interconnection,
it potentially excludes the protection system owner from having input in the process, and there is no redress for appeal by
the owner. It seems highly unlikely that elements that are not identified through criterion B4 will need to be included. If
some form of criterion B5 is included in Attachment B, then it needs to better define a technical basis for the request for
inclusion, a procedure to initiate the request for inclusion, due process defined for evaluation of the request, and inclusion
of the protection system owner in the evaluation process and the agreement.
Individual
J. S. Stonecipher, PE
City of Jacksonville Beach, FL dba/Beaches Energy Services
Yes
However, R1 and R2 have binary VSLs, where they should be percentages of all relays that need to meet the standard
based on statistical sampling.
Yes

R1 and R2 have binary VSLs, where they should be percentages of all relays that need to meet the standard based on
statistical sampling. (See previous comment for R1.)
No
No, that is way too frequent. It should be a much longer time criteria, say 5 years, with a requirement that if there is a
CHANGE, the information is sent to the PC, TO and RC.
No
No, once again, that is way too frequent and creates another unnecessary burden for record keeping. It should be a much
longer time criteria, say 5 years, with a requirement that if there is a CHANGE, the information is sent to the PC, TO and
RC.
Yes
Yes
Yes
Yes
Attachment B, the criterion in B4 seem rather arbitrary; but, the numbers seem reasonable.
Group
Midwest ISO Standards Collaborators
Jason Marshall
Yes

go far enough and still do not reflect the use of flowgates. NERC’s definition of flowgate includes two components. Let’s
focus on the first component which represents those flowgates defined in the IDC. Because IDC flowgates list is updated
monthly and the IDC users can add temporary flowgates to the IDC at any time, this is an inappropriate list to use. We
appreciate the drafting team’s attempt to resolve this issue by including the caveat “that has been included to address
long-term reliability concerns, as confirmed by the applicable Planning Coordinator.” However, this really only confuses the
matter and does not solve it. Reliability Coordinators add flowgates to manage real-time congestion. Planning
Coordinators do not. Per the NERC functional model, they do not even have a role in deciding which flowgates to add to
the IDC. Flowgates are added to the IDC to mitigate existing, known congestion points not congestion points identified in a
long-term planning study that may never materialize due to changing conditions. Thus, IDC flowgates should be
specifically excluded. Now let us focus on the second component of flowgate. The second component is much like the first
component in that is it a mathematical construct to analyze the impact of power flows on the BES except is not required to
be included in the IDC. There is nothing in the definition of a flowgate to give credence that is represents anything more
than point to calculate power flows and the impact of transactions. Flowgates are primarily used to manage congestion on
the system and to sell transmission system. Because it is convenient to select a group of lines as a proxy to sell
transmission service or manage congestion does not mean that those group of lines represent a reliability issue. Thus, we
do not believe any flowgates should be included in the list. Any true reliability issues can be identified through the TPL
studies and those facilities that do not meet the performance requirements are what should be used. We do not support
criterion B4. It exceeds what is required in the TPL standards and what is required per the reliability directive in Order 729.
The TPL standards allow system operator intervention for category C3 contingencies between the two independent
Category B contingencies. This standard should not exceed those requirements in the TPL standards. Paragraphs 79 and
80 of FERC Order 729 contain the relevant directives regarding the Planning Coordinator test. Paragraph 79 states that
the test “must include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in transmission
planning.” Paragraph 80 states that “the test must be consistent with the general reliability principles embedded in the
existing series of TPL” standards. Thus, exceeding the TPL standards could be argued as deviating from the directive. In
response to comments that did not support this criterion during the first posting, the standards drafting team responded
with “Testing multiple element contingencies while accounting for system adjustments between each element outage will
not yield any facilities to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We think
the drafting team missed a basic point about the standard. The issue is not whether the registered entity develops and
documents corrective action plans TPL-003-0a R2 and R3. The issue is if the system as currently designed meets the
performance requirements in TPL-003-0a R1 which allows for operator interventions on Category C3 contingencies. For
those C3 contingencies that don’t currently meet the performance obligations after operator interventions, the subject
facilities would be included PRC-023-2 R6 list of facilities.
Individual
Thad K. Ness
American Electric Power
No
American Electric Power sees two issues with R1's Criterion 10. First, transformer "mechanical withstand capability" is
undefined, vague, and subject to various interpretations. The terminology used in this criterion must be more tightly
defined to prevent ambiguity or else referenced to some agreed-upon standard such as IEEE C57.109-1993. Second,
American Electric Power agrees that it is appropriate for the 150% and 115% settings criteria to apply to line relays
terminated only with a transformer. However, Criterion 10 seems to assume that transmission line relays on transmission
lines terminated with a transformer are also typically intended to protect the transformer. This is not normally or
necessarily true. If the line relays are not intended to protect the transformer and as long as the transformer relaying
properly protects the transformer from mechanical damage, there is no reason for Criterion 10 to apply to the line relays.
To address these two deficiencies in Criterion 10, American Electric Power sets forth the following two-part replacement
language for Criterion 10: 10.1 Set transformer fault protection relays such that the protection settings do not expose the
transformer to fault level and duration that exceeds its mechanical withstand capability as defined by IEEE C57.109-1993
or its successor standard and so that the relays do not operate at or below the greater of: • 150% of the applicable
maximum transformer nameplate rating (expressed in amperes), including the forced cooled ratings corresponding to all
installed supplemental cooling equipment. • 115% of the highest operator established emergency transformer rating. 10.2
Set transmission line relays on transmission lines terminated only with a transformer so that the relays do not operate at or
below the greater of: • 150% of the applicable maximum transformer nameplate rating (expressed in amperes), including
the forced cooled ratings corresponding to all installed supplemental cooling equipment. • 115% of the highest operator
established emergency transformer rating. If the transformer fault protection relays on the line-terminated transformer do
not expose the transformer to fault level and duration that exceeds its mechanical withstand capability, then the
transmission line relays do not also need to provide the same protection against transformer mechanical damage.
Yes
Yes
Yes
No
The wording under Sections 4.2.3, 4.2.6, 6.2, and the applicability portion of Attachment B needs to be made consistent to
avoid any misinterpretations and confusion. - Section 4.2.3 – Delete the portion that reads “... and the Planning
Coordinator has determined are required to comply with this standard” for this section to read the same as the associated
sentence under the applicability portion of Attachment B. - Section 4.2.6 – Same comment as Section 4.2.3 (above). Section 6.2 – Reword to read: “Apply the criteria to transmission lines operated below 100 kV and transformers with low
voltage terminals connected below 100 kV that the Regional Entity has identified as critical for the purposes of the

Compliance Registry.”
No
Need to provide a 60-month timeline to implement the noted requirements for each facility that is added to the Planning
Coordinator’s initial list of facilities that must comply with this standard, versus the 24-month timeline to implement the
noted requirements for each facility that is added to the Planning Coordinator’s established list of facilities that must
comply with this standard. This is a practical consideration that recognizes the high likelihood that the number of facilities
that will be identified during development of the initial list of facilities will be many times greater than the incremental
number of facilities that will be identified during the annual assessments and added to the established list of facilities. In
addition, need to specify under this requirement whether any facilities that drop off the Planning Coordinator’s list of
facilities while still within the applicable (60-month or 24-month) implementation timeline must still comply with this
standard.
No
The wording of Attachment A, section 1.6 needs to be made consistent to avoid any confusion. 1.6 Reword to read:
"Supervisory elements used as fault detectors associated with pilot wire or current differential protection systems where
the system is capable of tripping for loss of communications".
No
Include the following refinements to the criteria for determining the facilities that must comply with the standard: o Add new
B5 that reads: “Each circuit that is operated below 100 kV that the Regional Entity has identified as critical for the
purposes of the Compliance Registry.” o Renumber B5 to B6. o Need to consider the amount of load that is placed at risk
when determining whether the circuit must comply with the standard. The threshold should be set at the DOE reporting
level of 300 MW. o Need to include a review and appeals process as part of the annual assessment for the Planning
Coordinator to review the proposed facilities with the transmission entity prior to adding those facilities to the Planning
Coordinator’s list of facilities that must comply with the standard.
Individual
Steve Wadas
Nebraska Public Power District
Yes
Yes
No
NERC does not need a separate requirement for TOs, GOs, and DPs to specifically report R1, criterion 2. If they meet the
requirement the line will not trip. If they meet the requirement and the line is overloaded the operator will receive an alarm
and will take action within 15 minutes.
Yes
Yes
If attachment B is kept then the PC should determine which transmission elements must comply with the standard.
Yes
Yes
No
Attachment B, Criteria B1 could add at least 24 transmission elements which are transmission lines operated at 100kv to
200kv. After reviewing the MRO and SPP criteria these lines will not be included per PRC-023. Loss of any of these lines
will not cause a cascading outage which PRC-023 is intended to prevent.
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
Yes
Yes
No
We do not believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission line’s
highest seasonal 15 minute rating does not equate to a line that will trip before the operator has time to intervene. It does
not mean the line will trip in 15 minutes. In fact, the operator should be taking action well in advance of reaching a 15
minute limit and the operator is likely only using the 15 minute rating in extreme circumstances. Furthermore, PRC-023-2
R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC-008-1 and FAC-009-1 already collectively require the
Transmission Owner and Generator Owner to establish a facilities ratings methodology, rate its facilities consistent with its
methodology and to communicate those ratings and methodology to its Planning Coordinator, Reliability Coordinator and
Transmission Operator. More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to
consider relay protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed. We assume the drafting team
must be aware of these FAC standard requirements because they did not even require reporting to the Reliability

Coordinator, Planning Coordinator and Transmission Operator of those circuits that are actually limited by the relay per
criterion 12. We agree that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits and that no additional requirements
are necessary.
No
While we don’t necessarily have an issue with the equipment owner communicating these relay limited circuits to the
Regional Entities, we don’t believe this is needed for reliability and therefore it should not be included in the reliability
standard. Given that it is unclear what the information will even be used for, if it will be needed long-term, and that it is
likely will not change much, if at all, from year to year, we believe a data request through NERC’s Rules of Procedure
section 1600 would be more appropriate. In that way, we don’t have to modify the standard later when NERC and the
Regions determine they don’t need the data annually.
No
It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has identified that are
below 100 kV that are part of the Bulk Electric System. This information is not readily available and there is no requirement
for the Regional Entity to communicate it to them. Thus, inaction by the auditor (i.e. Regional Entity) could actually cause
the Planning Coordinator to violate this requirement. This is clearly a conflict of interest. Why does the Planning
Coordinator need to identify which circuits are identified per criteria B4? There is no justification given for this need and
there is nothing else that appears to require action as a result of this information. Thus, it is purely administrative and
should be removed. Registered entities should never be subject to potential sanctions for violations of purely
administrative portions of requirements. Why does the Planning Coordinator need to provide this information to the
Reliability Coordinator? There is nothing for the Reliability Coordinator to do with the information. The Reliability
Coordinator only needs to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1.
No
We do not believe that R7 is needed. The applicability section of the standard is clear that the standard applies to those
circuits identified in R6. This requirement could be construed as potential for double jeopardy because failure to comply
with Requirements 1 through 5 would represent a violation of both Requirement 7 and Requirements 1 through 5.
Yes
No
While we appreciate the drafting team’s effort to refine the flowgate criteria from the last posting, the modifications do not
go far enough and still do not reflect the use of flowgates. NERC’s definition of flowgate includes two components. Let’s
focus on the first component which represents those flowgates defined in the IDC. Because IDC flowgates list is updated
monthly and the IDC users can add temporary flowgates to the IDC at any time, this is an inappropriate list to use. We
appreciate the drafting team’s attempt to resolve this issue by including the caveat “that has been included to address
long-term reliability concerns, as confirmed by the applicable Planning Coordinator.” However, this really only confuses the
matter and does not solve it. Reliability Coordinators add flowgates to manage real-time congestion. Planning
Coordinators do not. Per the NERC functional model, they do not even have a role in deciding which flowgates to add to
the IDC. Flowgates are added to the IDC to mitigate existing, known congestion points not congestion points identified in a
long-term planning study that may never materialize due to changing conditions. Thus, IDC flowgates should be
specifically excluded. Now let us focus on the second component of flowgate. The second component is much like the first
component in that is it a mathematical construct to analyze the impact of power flows on the BES except is not required to
be included in the IDC. There is nothing in the definition of a flowgate to give credence that is represents anything more
that point to calculate power flows and the impact of transactions. Flowgates are primarily used to manage congestion on
the system and to sell transmission system. Because it is convenient to select a group of lines as a proxy to sell
transmission service or manage congestion does not mean that those group of lines represent a reliability issue. Thus, we
do not believe any flowgates should be included in the list. Any true reliability issues can be identified through the TPL
studies and those facilities that do not meet the performance requirements are what should be used. We do not support
criterion B4. It exceeds what is required in the TPL standards and what is required per the reliability directive in Order 729.
The TPL standards allow system operator intervention for category C3 contingencies between the two independent
Category B contingencies. This standard should not exceed those requirements in the TPL standards. Paragraphs 79 and
80 of FERC Order 729 contain the relevant directives regarding the Planning Coordinator test. Paragraph 79 states that
the test “must include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in transmission
planning.” Paragraph 80 states that “the test must be consistent with the general reliability principles embedded in the
existing series of TPL” standards. Thus, exceeding the TPL standards could be argued as deviating from the directive. In
response to comments that did not support this criterion during the first posting, the standards drafting team responded
with “Testing multiple element contingencies while accounting for system adjustments between each element outage will
not yield any facilities to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We think
the drafting team missed a basic point about the standard. The issue is not whether the registered entity develops and
documents corrective actions plans per TPL-003-0a R2 and R3. The issue is if the system as currently designed meets
the performance requirements in TPL-003-0a R1 which allows for operator interventions on Category C3 contingencies.
For those C3 contingencies that don’t currently meet the performance obligations after operator interventions, the subject
facilities would be included PRC-023-2 R6 list of facilities.
Individual
Joe Knight
Great River Energy
Yes
Yes

No
We do not believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission line’s
highest seasonal 15 minute rating does not equate to a line that will trip before the operator has time to intervene. It does
not mean the line will trip in 15 minutes. In fact, the operator should be taking action well in advance of reaching a 15
minute limit and the operator is likely only using the 15 minute rating in extreme circumstances. Furthermore, PRC-023-2
R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC-008-1 and FAC-009-1 already collectively require the
Transmission Owner and Generator Owner to establish a facilities ratings methodology, rate its facilities consistent with its
methodology and to communicate those ratings and methodology to its Planning Coordinator, Reliability Coordinator and
Transmission Operator. More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to
consider relay protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed. We assume the drafting team
must be aware of these FAC standard requirements because they did not even require reporting to the Reliability
Coordinator, Planning Coordinator and Transmission Operator of those circuits that are actually limited by the relay per
criterion 12. We agree that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits and that no additional requirements
are necessary.
No
While we don’t necessarily have an issue with the equipment owner communicating these relay limited circuits to the
Regional Entities, we don’t believe this is needed for reliability and therefore it should not be included in the reliability
standard. Given that it is unclear what the information will even be used for, if it will be needed long-term, and that it is
likely will not change much, if at all, from year to year, we believe a data request through NERC’s Rules of Procedure
section 1600 would be more appropriate. In that way, we don’t have to modify the standard later when NERC and the
Regions determine they don’t need the data annually.
No
It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has identified that are
below 100 kV and that are part of the Bulk Electric System. This information is not readily available and there is no
requirement for the Regional Entity to communicate it to them. Thus, inaction by the auditor (i.e. Regional Entity) could
actually cause the Planning Coordinator to violate this requirement. This is clearly a conflict of interest. Why does the
Planning Coordinator need to identify which circuits are identified per criteria B4? There is no justification given for this
need and there is nothing else that appears to require action as a result of this information. Thus, it is purely administrative
and should be removed. Registered entities should never be subject to potential sanctions for violations of purely
administrative portions of requirements. Why does the Planning Coordinator need to provide this information to the
Reliability Coordinator? There is nothing for the Reliability Coordinator to do with the information. The Reliability
Coordinator only needs to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1
No
We do not believe that R7 is needed. The applicability section of the standard is clear that the standard applies to those
circuits identified in R6. This requirement could be construed as potential for double jeopardy because failure to comply
with Requirements 1 through 5 would represent a violation of both Requirement 7 and Requirements 1 through 5.
Yes
No
While we appreciate the drafting team’s effort to refine the flowgate criteria from the last posting, the modifications do not
go far enough and still do not reflect the use of flowgates. NERC’s definition of flowgate includes two components. Let’s
focus on the first component which represents those flowgates defined in the IDC. Because the IDC flowgates list is
updated monthly and the IDC users can add temporary flowgates to it at any time, this is an inappropriate list to use. We
appreciate the drafting team’s attempt to resolve this issue by including the caveat “that has been included to address
long-term reliability concerns, as confirmed by the applicable Planning Coordinator.” However, this really only confuses the
matter and does not solve it. The Reliability Coordinator adds flowgates to manage real-time congestion. The Planning
Coordinator does not. Per the NERC functional model, they do not even have a role in deciding which flowgates to add to
the IDC. Flowgates are added to the IDC to mitigate existing, known congestion points not congestion points identified in a
long-term planning study that may never materialize due to changing conditions. Thus, IDC flowgates should be
specifically excluded. Now let us focus on the second component of flowgate. The second component is much like the first
component in that it is a mathematical construct to analyze the impact of power flows on the BES except it is not required
to be included in the IDC. There is nothing in the definition of a flowgate to give credence that it represents anything more
that point to calculate power flows and the impact of transactions. Flowgates are primarily used to manage congestion on
the system and to sell transmission system. Because it is convenient to select a group of lines as a proxy to sell
transmission service or manage congestion does not mean that those group of lines represent a reliability issue. Thus, we
do not believe any flowgates should be included in the list. Any true reliability issues can be identified through the TPL
studies and those facilities that do not meet the performance requirements are what should be used. We do not support
criterion B4. It exceeds what is required in the TPL standards and what is required per the reliability directive in Order 729.
The TPL standards allow system operator intervention for category C3 contingencies between the two independent
Category B contingencies. This standard should not exceed those requirements in the TPL standards. Paragraphs 79 and
80 of FERC Order 729 contain the relevant directives regarding the Planning Coordinator test. Paragraph 79 states that
the test “must include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in transmission
planning.” Paragraph 80 states that “the test must be consistent with the general reliability principles embedded in the
existing series of TPL” standards. Thus, exceeding the TPL standards could be argued as deviating from the directive. In
response to comments that did not support this criterion during the first posting, the standards drafting team responded
with “Testing multiple element contingencies while accounting for system adjustments between each element outage will

not yield any facilities to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We think
the drafting team missed a basic point about the standard. The issue is not whether the registered entity develops and
documents corrective actions plans per TPL-003-0a R2 and R3. The issue is if the system as currently designed meets
the performance requirements in TPL-003-0a R1 which allows for operator interventions on Category C3 contingencies.
For those C3 contingencies that don’t currently meet the performance obligations after operator interventions, the subject
facilities would be included PRC-023-2 R6 list of facilities.
Group
Santee Cooper
Terry L. Blackwell
Yes
No
We appreciate the drafting team addressing this issue, and, in general, agree with our understanding of the intention of
this requirement. However, the wording of the section should be a little clearer. Through asking questions about the
intention of these statements, it is our understanding that, as long as the composite scheme (made up of all the relay
elements protecting the transmission line) will still operate for a fault in a time that is compliant with the TPL standards,
that this requirement is met. This may mean that a particular relay element may still be blocked, but there are other relay
elements, possibly with a different time delay, that would still operate in an appropriate amount of time. As long as the total
scheme protecting the element in question still meets all of the TPL and stability requirements for isolating the fault from
the system, the operation of the scheme should be satisfactory. If this is still the intention, then it should be clarified in this
requirement.
Yes
Yes
Yes
Yes
Yes
No
The criteria in Attachment B lack clarity. For example, B4 criteria for powerflow analysis does not specify a horizon. In
addition, in B1 does that only apply to circuits that are monitored by you or the IDC? Assessing the post-contingency
loading and determining if a facility rating is based on loading durations of specified time periods is too burdensome and
would not provide much value.
Individual
Dan Rochester
Independent Electricity System Operator
No
Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection to protect from
mechanical damage. The wording in criterion 10 should be changed to “set transformer fault protection relay or
transmission line relay on transmission line terminated with only a transformer.” Is this criteria requiring that a transformer
with only differential protection and no other load responsive remote protection be mitigated with additional load
responsive protection?
Yes
No
As indicated in our previous comments, the FERC Directive asks for provision of this information to the TOP only. We
question the need to go beyond what’s being asked for in the Directive to require the responsible entities to provide this
information to other entities (PC and RC). If a reliability need is not identified, we suggest that these two entities be
removed from the requirement.
Yes
No
We agree that the PC should be held responsible for conducting the annual assessment, but we do not understand the
need for including “if the Regional Entity has identified either of these Element types as critical facilities for the purposes of
the Compliance Registry” in R6.2. We also do not understand the meaning of “as critical facilities for the purpose of
Compliance Registry”. There are established criteria for compliance registry, but we are not aware of what constitutes
“critical facilities for the purpose of compliance registry”. For the purpose of determining compliance with the relay
loadability requirements, having the PC to make such an assessment and determination would suffice. If the intent is to
limit the facilities to be assessed to only those that have been identified as “critical facilities for the purpose of compliance
registry”, then it implies that those that are not identified are not required to be assessed. This may in fact result in missing
some facilities that may be critical from a relay loadability standpoint. Further, the term “critical facilities” is used very
loosely in different standards, and can mean very different things for various applications and under various

circumstances. We suggest to remove ““if the Regional Entity has identified either of these Element types as critical
facilities for the purposes of the Compliance Registry” from the requirement. For the same reason, we suggest the quoted
phrase be removed from the Applicability Section, any other requirements in this standard, and Attachment B.
Yes

No
We commented on Criterion 6 (now B4) related to TPL-003 Category C contingencies in the previous posting but we see
no evidence that our comment was addressed. We therefore reiterate our position. The PC and TP assess their future
systems according to the performance requirements stipulated in the TPL standards, including those in TPL-003. We
question the requirement to have Planning Coordinators assess the impact of double contingencies with no manual
system adjustments in between since this is not required by TPL-003. This goes beyond the basic planning and design
requirements and in our view should be removed from Criterion B4. We also believe Criterion B4 should be rewritten for
greater clarity. The second bullet seems unnecessary since the post contingency loading on each circuit will not in fact be
compared against its Facility Rating to determine applicability of PRC-023-2 but against the corresponding “applicability
threshold”. Also, the third bullet seems to conflict with the fourth, since the forth bullet allows for determining thresholds
based on Facility Ratings that assume various loading durations, whereas the third bullet links determination of the
threshold to the Facility Rating for a duration nearest four hours only. We therefore suggest the following alternative
wording for B4: B4. Each circuit operated between 100 kV and 200 kV identified by applying the following procedure:
B4.1Establish Thresholds of Applicability – (text of 4th bullet of B4) B4.2 Conduct Analysis – Conduct power flow analysis
to simulate double contingency combinations selected by engineering judgment as indicated in TPL-003 Category C3.
B4.3 Evaluate Applicability of PRC-023-2 – Compare post contingency loading of each circuit against its corresponding
threshold determined in B4.1. Indicate the applicability of standard PRC-023-2 to each circuit for which the post
contingency loading exceeds the corresponding threshold. B4.4 Exclusion - Radial circuits serving only load are excluded.
Group
Bonneville Power Administration
Denise Koehn
No
BPA believes that FERC does not fully understand how transformers are rated and applied on the Bulk Electric System.
Therefore, we believe the concern they expressed in their NOPR and Order 733 regarding the reliability of the Bulk
Electric System being jeopardized by operating a transformer at 150% of its nameplate rating is unfounded. In response to
FERC’s concern, NERC has modified Criterion 10, which now has two conflicting requirements—ensuring that there is no
operation for one level of load and ensuring that there is operation for another level of load. In some cases, these two load
levels overlap and both requirements cannot be achieved simultaneously. The requirement in Criterion 10 that the
protection settings do not expose the transformer to fault level and duration that exceeds its mechanical withstand
capability is ambiguous. It is not clear how the mechanical withstand capability is to be determined. IEEE Standard
C57.109 provides recommended transformer through-fault duration limits, but these do not represent the actual
mechanical withstand capability of transformers. IEEE Standard C57.12.00 specifies that transformers shall be designed
and constructed to withstand the mechanical and thermal stresses produced by a fault limited only by the transformer
impedance, or for category III and IV transformers, transformer impedance plus system impedance, for a duration of two
seconds. However, the standard specifies that for currents between rated current and maximum short-circuit current the
allowable time duration should be obtained by consulting the manufacturer. These standards do not clearly indicate what
the mechanical withstand capability of transformers are. Certainly, for many existing transformers, there is no available
manufacturer’s data for this either, and it is unclear how to comply with Criterion 10. BPA feels this is too ambiguous and
exposes entities to an unnecessary risk of possibly being sanctioned based on the judgment of an auditor. BPA believes
that FERC’s concern about transformer damage at the loading levels addressed by this standard is unfounded and
contradictory to the purpose of this standard. The purpose of PRC-023 is to prevent automatic relay operations--which
could cause cascading outages and quickly deteriorate the reliability of the BES--during severe system loading conditions.
Under these loading conditions it is desirable that system operators have time to take corrective action to mitigate system
problems before automatic relay operations accelerate the problem into a blackout. IEEE Standard C57.109 indicates that
transformers can sustain 200% of rated load for at least thirty minutes. If relays are set to operate in this range, they are at
risk of tripping a transformer under emergency loading situations, which exasperates the very problem that PRC-023 is
attempting to eliminate. Most utilities have developed emergency ratings for their transformers. When a transformer load
exceeds a predetermined level, the system operators are alarmed so that they can take appropriate action. During
stressed system conditions, allowing a critical transformer to operate up to these emergency ratings could prevent a
blackout. Conversely, requiring relays to be set in this range could result in the automatic loss of critical transformers,
thereby accelerating the collapse of the bulk electric system. The ability of transformers to carry load without thermal
damage or with acceptable levels of loss of life has been under study for many decades. There are many variables, such
as ambient temperature, duty cycle, acceptable loss of life, etc., that determine the load and duration that a transformer is
capable of. It has been addressed in transformer design and relay protection standards. Many utilities have made
considerable efforts to determine the appropriate levels of emergency loading for their transformers. The mechanical
withstand capability of a transformer is not the relevant factor at the load levels addressed by PRC-023. BPA is concerned
that we might be on the verge of superseding these many decades of research and experience with a poorly written,
ambiguous, and inapplicable requirement because of the misunderstanding of the FERC commissioners. BPA suggests
that NERC resist FERC’s demands for setting relays to operate within the emergency operating capabilities of
transformers. Additionally, BPA believes that there is no reason for FERC to be concerned with transformer overload
protection. There is not a widespread problem with transformers being overloaded, and placing requirements on the
industry for transformer protection results in an increased burden and expense to the industry with no resulting benefits.
The subject of transformer loading has gained FERC’s attention only as a result of its inclusion in PRC-023, and is not a
problem for the BES—mostly because the industry has done the opposite of what FERC is now asking and not set
transformer relays to operate in the emergency loading region. If transformer protection were an issue, it would be worthy

of an individual standard, separate from PRC-023, because it is too complex to address in a short paragraph such as
Criterion 10. Finally, BPA believes that Requirement 1 is unclear. It states that each TO, GO, and DP shall use any one of
the 13 criteria for any specific circuit terminal to prevent its phase protective relays from limiting transmission loadability.
Does this mean that the requirements of Criterion 10 only apply if Criterion 10 is used as the basis for justifying the relay
settings of a terminal? If the relay settings for a transformer-terminated line are justified by one of the other criteria, say
Criterion 1, is an entity allowed to ignore the requirements of Criterion 10 for the transformer overcurrent relays? Are
transformer relays for transformers that aren’t part of a transformer-terminated line subject to Criterion 10? BPA
recommends that the words “such that the protection settings do not expose the transformer to fault level and duration that
exceeds its mechanical withstand capability” be removed from Criterion 10. In addition, if all transformer overcurrent
relays—not just those for transformer-terminated lines—are subject to the requirements of Criterion 10 (as suggested by
Attachment A), they need to be addressed in a separate requirement because the 13 criteria of Requirement 1 are not
necessarily mandatory.
Yes
No
BPA does not understand why a list of such facilities must be provided each year. These facilities will not change very
often, and a new list should only be required when changes are made to the old list. Please explain why you feel it is
necessary.
No
Since a Registered Entity is already required to obtain the agreement of the Planning Coordinator, Transmission Operator,
and Reliability Coordinator and to use the calculated circuit capability as the Facility Rating of the circuit as required by R3,
BPA would like additional information regarding the purpose of providing the Regional Entity a list each year. What would
they do with the list?
No
BPA feels the applicable date descriptions are too confusing and would like to see more clarity and simplification.
Yes
No
The evaluation method seems technically sound. The second category of applicable circuits, "Transmission lines operated
below 100 kV and transformers with low voltage terminals connected below 100 kV ...", are not considered BES elements
based on the latest definition and BPA does not believe that this category of circuits should be included.
Individual
Michael R. Lombardi
Northeast Utilities
No
Further clarification is needed for this criterion. Is it the intention of this criterion that all applicable transformers must have
load responsive protection to prevent mechanical damage from a through fault? If load responsive protection for the
transformer element does not presently exist, i.e. only differential protection exists for the transformer element, will load
responsive transformer protection have to be added to comply with this criterion? It is also suggested that R1 Criterion 10
wording be changed to “Set transformer fault protection relays or transmission line relays on transmission lines terminated
only with a transformer to …….” since it appears from the NERC Webinar on 11/23/10 that the intention was address the
possible locations where phase protection for the transformer could exist and not infer that this protection was needed at
both locations.
No
What is the expectation for verification that the out-of-step blocking elements allow tripping of phase protection relays for
faults that occur duing the loading conditions used to verify transmission line relay loadability? It would be very costly and
time consuming to verify proper operation of these blocking schemes for all of the various possible fault and loading
combination scenarios for each application of this scheme.
Yes
Suggest clarification for Section 4.2.6 be added. That is, our review of the draft indicates that, as its title implies, this
Standard primarily focuses on transmission relaying for lines and transformers. Nowhere does it mention generation
relaying, per se, and the transformer relaying appears to be focused on “transmission” transformers and other
transformers that have bi-directional flow capability. There is one sticking point, however. Section 4.2.6 seems to muddy
the otherwise clear “transmission” directive in that it extends the applicability to: “4.2.6 Transformers with low voltage
terminals connected below 100 kV that Regional Entities have identified as critical facilities for the purposes of the
Compliance Registry and the Planning Coordinator has determined are required to comply with this standard”. While we
believe that this was intended to pertain to transmission or load-serving transformers, due to ambiguity in the Standard this
could be taken to mean transformers in facilities deemed “material to the reliability of the Bulk Power System.” It could
thus be applied (incorrectly, in our opinion) to generation facilities. We would also question why there would be a concern
for the low voltage side of a GSU. Please clarify Section 4.2.6, as appropriate.
Yes
Yes
Yes

Yes
Yes
Individual
Armin Klusman
CenterPoint Energy

No
CenterPoint Energy disagrees with providing a list to Planning Coordinators, Transmission Operators, and Reliability
Coordinators, as we cannot see any need and do not expect these entities would utilize this information in any manner.
No
CenterPoint Energy disagrees with providing a list, as we cannot see any need and do not expect the Regional Entity
would have any use for this information. In discussions with Regional Entity personnel, they were unsure of what use they
would have for this information.
No
(a) CenterPoint Energy recommends revising R6 to require Planning Coordinators to coordinate with associated
Transmission Planners in the determination of which 100 – 200 kV elements must comply with this standard. (b)
CenterPoint Energy recommends criterion B5 be deleted, as it is too broad and gives the Planning Coordinator too much
discretion in determining other facilities which must comply with this Standard. In the case that criteria B5 is not deleted,
CenterPoint Energy recommends that a process be required where Transmission Planners can appeal the inclusion of
specific Transmission elements that must comply with this standard. (c) CenterPoint Energy recommends eliminating the
un-capitalized term “critical” to remove any confusion with NERC CIP reliability standards. The voluntary NERC relay
loadability review in 2006 used the term “operationally significant element” for elements 100 – 200 kV. CenterPoint Energy
recommends using “operationally significant” wherever “critical” is used within PRC-023-2.
No
CenterPoint Energy believes Requirement 7 should be deleted from PRC-23-2, as it an Effective Date / Implementation
Plan issue. Instead the wording should be included in PRC-023-2 in Effective Dates item 5.5 and within the
Implementation Plan.
No
(a) Criterion B3 indicates any path that is used to supply off-site power to nuclear plants, as agreed to by the plant owner
and the Transmission Entity. If the purpose of attachment B is to provide “bright line” criteria, then a negotiated agreement
would not qualify as “bright line”. Additionally, off-site power requirements are meant to ensure safe shutdown of nuclear
reactors in a system restoration event where transmission lines are lightly loaded. CenterPoint Energy recommends
criterion B3 be deleted. (b) Considering situations where the transmission system may be at risk of cascading outages or
voltage collapse, sub-200 kV elements should be considered operationally significant only whenever reasonably
contemplated scenarios would cause high amperage and low voltage to be experienced on the elements. Criteria B4.a in
Attachment B proposes loading exceeding 115% of a two or four hour rating following a double contingency, without
manual system adjustments. CenterPoint Energy believes this is not a technically sound method to indicate if an element
is operationally significant.
Group
New York Power Authority
Bruce Metruck
No
Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection to protect from
mechanical damage, either from internal faults, or through faults. If load responsive protection for the transformer element
does not presently exist, i.e. only differential protection exists for the transformer element, will load responsive transformer
protection have to be added to comply with this criterion? The wording in criterion 10 should be changed to “Set
transformer fault protection relays or transmission line relays on transmission lines terminated only with a transformer to
…….” Is this criteria requiring that a transformer with only differential protection and no other load responsive remote
protection be supplemented with additional load responsive protection? The loading on phase angle regulators, and series
reactors should be considered and mentioned. Also, there appears to be words missing in criterion 9 of R1: “the maximum
current flow from the ? to the ? under any system configuration.” From the NERC Webinar on 11/23/10 the intention was
to address the possible locations where phase protection for the transformer could exist and not imply that this protection
was needed at both locations.
Yes
Yes
Yes
Yes

Yes
Yes
No
B2. Item B2 adds significant confusion to the process. The long term planning horizon may include transmission projects
which have not even been built or alternative system configurations which do not exist, making it impossible for affected
parties to set their relays appropriately. Suggested replacement language to avoid this issue: “Each circuit that is a
monitored element of an IROL, assuming that all transmission elements are in service and the system is under normal
conditions.” B3. This item indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement by the plant and
the Transmission Entity it should be removed from Attachment B and placed elsewhere in the document. If this is intended
to apply to the Planning Coordinator, Transmission Entity should be replaced with Planning Coordinator. Why does B3
only apply to Nuclear Power Plants? B4. This criterion is overly stringent and should be deleted. The system is neither
planned nor operated to allow for two overlapping outages without operator action in between. If this criterion is retained, it
should be made consistent with the requirements of TPL-003 where operator actions can be assumed between the first
and second contingencies. Since a similar comment was made previously, more information is being provided following. 1.
Since the system is neither planned nor operated to two overlapping outages in between, such testing may result in
unsolved cases, or voltages well below criteria. In the case of an unsolved case, there are no flows to evaluate, making
this standard impossible to apply. In the case of a solved case with voltages well below criteria, currents are likely to be
incredibly high and therefore viewed as unrealistic. These concerns may limit the contingency selection to those which are
not severe, eliminating any perceived benefit from this testing. 2. There is no guidance provided on how the system should
be dispatched in the model upon which the overlapping contingencies are tested. This will result in significant
discrepancies between the base assumptions used by the various Planning Coordinators. The contents of this standard
should be reviewed to reflect the new definition of the Bulk Electric System.
Group
FirstEnergy
Doug Hohlbaugh
No
Criterion 10 does not take bidirectional load flow into consideration which could compromise the entity’s ability to provide
backup protection for the transmission system. We suggest the following wording for criterion 10: “Set transformer fault
protection relays and transmission line relays on transmission lines terminated only with a transformer such that the
protection settings do not expose the transformer to fault level and duration that exceeds its mechanical withstand
capability and so that the relays do not operate at or below the greater of:  150% of the applicable maximum transformer
nameplate rating (expressed in amperes), including the forced cooled ratings corresponding to all installed supplemental
cooling equipment for load flow from the normal source side to the normal load side.  115% of the highest operator
established emergency transformer rating for load flow from the normal source side to the normal load side.  115% of the
maximum current flow from the normal load side to the normal source side under any system configuration.” We also ask
that the team consider similar wording be added to Criterion 11 as suggested above for consistency with Criterion 10.
Criterion 9 seems to be missing some words in the phrase “flow from the to the under any system configuration”. It
appears this should say “from the load to the system under any system configuration.”
Yes
Yes
No
FE recognizes that the standard drafting team introduced Requirement R5 in response to a FERC directive requiring
NERC to document and make available upon request a list of protective relays set pursuant to Requirement R1, Criterion
12. We commend FERC in their Order 733 decision to retain Criterion 12 over accepting the preceding NOPR
recommendation to remove it and support FERC’s desire in making information readily available on entities application of
Criterion 12 for its own use and other interested parties. We are not opposed to providing our Regional Entity the
information desired but believe this presents an administrative task that can be accomplished outside of a mandatory and
enforceable reliability requirement. Since the reported data is for informational purposes and not a reliability need, we
encourage the drafting team propose to NERC staff an equally efficient and effective alternative of having the Regional
Entity periodically obtain the data through NERC’s Rules of Procedure, Section 1600 titled “Request for Data or
Information”.
Yes
While we agree with the intent of Requirement R6, FE believes improvements can be made to simplify and clarify the R6
text. a. Items 6.1 and 6.2 can be removed as they are duplicative with the two bulleted items listed at the forefront of
Attachment B. b. Item 6.3 is awkwardly written based on the circular reference to R6. Its suggested that Item 6.3 be rewritten to say “Maintain a list of transmission Facilities operated below 200kV and deemed applicable to the PRC-023
standard per application of Attachment B” c. Requirement R6 and Attachment B text seem to mix and interchange
references to Glossary of Term definitions “Elements” and “Facility”, although facility(ies) is often not capitalized, such that
they are used synonymously. As one example R6 indicates “…determine which transmission Elements must comply with
this standard …” compared to Attachment B which says “… to determine the facilities which must comply with this
standard.” Sub items of R6 refer to keeping a list of “facilities” and not “Elements” as referenced in the parent R6
requirement. For greater consistency we suggest the use of the term “Facility(ies)” over “Element”. d. If the team believes
a reference to a Planning Coordinator only needing to cover transmission facilities within their footprint is needed, such as

used in items 6.1 and 6.2 which are proposed for removal, the team could revise the parent R6 text to read “ … to
determine which transmission Elements [Facilities] in its Planning Coordinator area must comply with this standard.” e.
Replace the word “year” in item 6.5 with “planning study year”. Its also recommended that the same change occur in R7,
to better clarify what “year” is referring to in R7.
Yes
We support the minimum 24 month implementation timeframe because a responsible entity will need sufficient time to
allow for any capital expenditures that may be required due to additional facilities identified by the Planning Coordinator.
Yes
No
FE proposes that criterion B1 be removed from Attachment B. We support criterion B3 as written and proposed revised
versions of criterion B2 and B4. a. Item B1 implies all facilities operated below 200kV and associated with a Flowgate must
comply with the PRC-023 standard. We support both MISO’s and PJM’s view that this criterion should be removed since
Flowgates in their truest sense is used for economic and market transmission needs over reliability needs. Flowgates
describe a designated point on the transmission system through which the Interchange Distribution Calculator (IDC)
calculates the power flow from Interchange Transactions. While its recognized the drafting team attempted improve the
Flowgate criteria by including a statement “that has been included to address a long-term reliability concerns, as confirmed
by the applicable Planning Coordinator”, it is FE’s opinion that a Planning Coordinator does not play a role in adding or
revising Flowgates used in the IDC and do not utilize Flowgates for long-term reliability planning purposes. Flowgates are
a means of managing congestion and for identifying available transfer capability. Continued use of this criterion will only
serve to confuse and complicate matters. b. Item B2 should be revised to include not only the monitored facilities
associated with the IROL, but also any “contingent” facilities that may describe the IROL condition. For example, it is
important to include the transmission facilities described in a NERC C3 contingency that may be associated with an IROL
definition. A C3 contingency describes a N-1-1 condition with system adjustments permitted in between the 1st and 2nd
contingency. It is necessary to ensure that the 2nd contingent facility does not prematurely trip due to a relay loadability
limitation. For greater consistency with terminology used in the FAC-014 standard, Requirement R5.1 we propose the
following for criterion B2: “B2. Each circuit monitored as critical to the derivation of an IROL and each circuit associated
with the Contingency(ies) that describe the need for the IROL.” c. We support criterion B3 as written. d. In regards to
criterion B4, FE supports the team’s recommendation for the Planning Coordinator to perform a modified NERC Category
C3 analysis to further identify sub 200kV facilities applicable to the PRC-023 standard. However, the sub-bullets
identifying various loading thresholds depending on the Facility rating is overly complicated and creates undue burden for
the Planning Coordinator performing the study. We propose that the team simplify this criterion to clarify the applicable
facilities are those that exceed 130% of their continuous emergency rating for the modified NERC Category C3 test.
Individual
Gregory Campoli
New York Independent System Operator
Yes
No comment from the PC & RC perspective, the TOs are responsible for designing phase protection schemes appropriate
to their systems
No
PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1, and therefore unnecessary. FAC-008-1 and FAC009-1 already collectively require the Transmission Owner and Generator Owner to establish a facilities ratings
methodology, rate its facilities consistent with its methodology and to communicate those ratings and methodology to its
Planning Coordinator, Reliability Coordinator and Transmission Operator. More specifically FAC-008-1 R1.2.1 requires the
Transmission Owner and Generator Owner to consider relay protective devices in its ratings methodology and FAC-009-1
R2 requires the communication of the ratings including those limited by relays.
Yes
No
Wording for R6.2 is confusing. It is not clear how the Planning Coordinator is supposed to know which facilities the
Regional Entity has identified that are below 100 kV. This information is not readily available and there is no requirement
for the Regional Entity to communicate it to them. Revise to clearly state the intent of the requirement is for registered
entities to report to Regional Entities those applicable facilities below 100kV and that the requirement for Regional Entities
is only to make that list available. There is no justification given in R6.4 for the need to identify facilities for which criterion
B4 applies and there is no further required action as a result of this information. Thus, it is purely administrative and should
be removed. Registered entities should never be subject to potential sanctions for violations of purely administrative
portions of requirements.
No
R7 is unnecessary as the applicability section of the standard is clear that the standard applies to those circuits identified
in R6. This requirement could be construed as potential for double jeopardy because failure to comply with Requirements
1-5 represents a violation of both Requirement 7 and Requirements 1-5.
Yes
No
Flowgates are primarily used to manage congestion on the system and to sell transmission system. Because it is
convenient to select a group of lines as a proxy to sell transmission service or manage congestion does not mean that
those group of lines represent a reliability issue. Thus, flowgates should not be included in the list as currently specified in

B1. Any true reliability issues can be identified through the TPL studies and those facilities that do not meet the
performance requirements are what should be applicable here. B2 adds significant confusion to the process. The long
term planning horizon may include transmission projects which have not even been built or alternative system
configurations which do not exist, making it impossible for affected parties to set their relays appropriately. Suggested
replacement language to avoid this issue: “Each circuit that is a monitored element of an IROL, assuming that all
transmission elements are in service and the system is under normal conditions.” B3 indicates that the circuits to be
considered are to be agreed to by the plant owner and the Transmission Entity. Attachment B is applicable to the Planning
Coordinator. If this item is by agreement by the plant and the Transmission Entity it should be removed from Attachment B
and placed elsewhere in the document. If this is intended to apply to the Planning Coordinator, Transmission Entity should
be replaced with Planning Coordinator. The B4 criterion is overly stringent and should be deleted. The system is neither
planned nor operated to allow for two overlapping outages without operator action in between. Paragraphs 79 and 80 of
FERC Order 729 contain the relevant directives regarding the Planning Coordinator test. Paragraph 79 states that the test
“must include or be consistent with the system simulations and assessments that are required by the TPL Reliability
Standards and meet the system performance levels for all Category of Contingencies used in transmission planning.”
Paragraph 80 states that “the test must be consistent with the general reliability principles embedded in the existing series
of TPL” standards. If this criterion is retained, it should be made consistent with the requirements of TPL-003 where
operator actions can be assumed between the first and second contingencies.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
No
In paragraph 209 of Order No 733 it states: Since Requirement R1.10 applies to any topology, it must be robust enough to
address the reliability issues of any topology. In light of the above statement criterion 10 of Requirement R1 should be
modified to read as follows: Set transformer fault protection relays and transmission line relays used for transformer fault
protection such that the protection settings do not expose the transformer to fault level and duration that exceeds its
mechanical withstand capability and so that the relays do not operate at or below the greater of: By eliminating the special
topology of “transmission lines terminated only with a transformer” from criterion 10 it eliminates any ambiguity that the
criterion only applies to special transmission line cases and complies with the FERC assertion that the Requirement
“applies to any topology.” Oncor like other Transmission Owners provides autotransformer protection from possible
thermal damage due to either prolonged through faults or load with its transformer overload protection relays. Protection of
all autotransformers from fault level and duration that exceeds their mechanical withstand capability is provided by the
redundant phase and ground relay settings of the local zones of protection coupled with local breaker failure protection.
For prolonged faults that are outside the local zones of protection (not threatening damage to the transformer by
exceeding the mechanical withstand capability of the transformer) or where loads exceed the thermal rating of the
transformer the phase and ground transformer overload protection relays protect the transformer from thermal damage.
Based on the fact that at many locations a transformer is protected by local Protection Systems from prolonged “Close in”
phase and ground through faults that might be within the fault level and duration that exceeds their mechanical withstand
capability, criterion 11 of Requirement R1 should be modified as follows: For transformer overload protection relays that
do not comply with the loadability or mechanical withstand capability components of Requirement R1, criterion 10 set the
relays according to one of the following: If transformer protection from fault level and duration that exceeds a transformer’s
mechanical withstand capability is provided by other Protection Systems, set the transformer overload protection settings
to not expose the transformer to current level and duration that exceeds its thermal withstand capability and so that the
relays do not operate at or below the greater of 150% of the applicable maximum transformer nameplate rating
(expressed in amperes), including the forced cooled ratings corresponding to all installed supplemental cooling equipment
or 115% of the highest operator established emergency transformer rating. Set the relays to allow the transformer to be
operated at an overload level of at least 150% of the maximum applicable nameplate rating, or 115% of the highest
operator established emergency transformer rating, whichever is greater, for at least 15 minutes to provide time for the
operator to take controlled action to relieve the overload. Install supervision for the relays using either a top oil or
simulated winding hot spot temperature element set no less than 100° C for the top oil temperature or no less than 140° C
for the winding hot spot temperature. Oncor believes that criterion 10 of Requirement R1 needs to be further modified as
stated above to ensure that it applies to transmission lines of any topology and not just to transmission lines terminated
only with a transformer. Oncor also feels that modifying criterion 10 of Requirement R1 by adding a requirement to ensure
that protection settings do not expose transformers to fault level and duration requires that, for the reasons stated above,
criterion 11 of Requirement R1 must be modified as noted above.
Yes
No
Oncor feels that the Requirement R4 is too cumbersome for the Registered Entities who have to, every 12 to 15 months,
provide to the Planning Coordinator, Transmission Operator and Reliability Coordinator massive amounts of information
that rarely changes. Also by allowing up to 15 months between reports to the Planning Coordinator, Transmission
Operator and Reliability Coordinator of relay setting changes made by Registered Entities these Operators and
Coordinators are deprived of knowing changes to loading limitations for up to 15 months. To overcome the problems with
Requirement R4 of the present version PRC-023-2 Oncor has two specific suggestions for improvement. First,
Requirement R4 should be changed to have a one time requirement for Each Transmission Owner, Generator Owner, and
Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis for verifying transmission line relay
loadability to provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with a list of facilities
associated with those transmission line relays. Second, Requirement R4 should be changed to require Each Transmission
Owner, Generator Owner, and Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis for
verifying transmission line relay loadability to provide its Planning Coordinator, Transmission Operator, and Reliability
Coordinator with any changes (additions, deletions or modifications) to the one time list of facilities associated with those
transmission line relays within 30 days changes are made to list. By using the proposed changes to R4 listed above, the

only information that needs be transferred between the Registered Entities and the Operators and Coordinators following
the initial exchange of information are changes made to the initial information. By requiring the Registered Entities to notify
the Operators and Coordinators shortly after changes are made the up to 15 month delay getting modifications to them is
eliminated.
No
Oncor feels that the Requirement R5 is too cumbersome for the Registered Entities who have to, every 12 to 15 months,
provide the Regional Entity a list of all the facilities that under Requirement R1 criterion 12 are limited by the requirement
to adequately protect the transmission line and cannot meet loadablity. It would better for the Registered Entities to
provide a one time list to its Regional Entity and then provide to the Regional Entity any additions or deletions to the list no
more than 30 days following any changes to the relaying what would remove or add a transmission line to the list.
Yes
Yes

Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
R1 - Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection to protect
from mechanical damage. The wording in criterion 10 should be changed to “set transformer fault protection relay or
transmission line relay on transmission line terminated with only a transformer.” Is this criterion requiring that a transformer
with only differential protection and no other load responsive remote protection be mitigated with additional load
responsive protection? The loading on phase angle regulators, and series reactors should also be considered and
mentioned. Also, there appears to be words missing in criterion 9 of R1: “the maximum current flow from the ? to the ?
under any system configuration.”
No
R2 - What is the expectation for verifying that the out-of-step (OOS) blocking elements allow tripping of phase protection
relays for faults that occur during the loading conditions used to verify transmission line relay loadability? It would be costly
and time consuming to verify this. To comply with this requirement, utilities may have to remove OOS protections all
together.
Yes
Yes
Yes
Yes
Yes
No
Attachment B - Why does B3 only apply to Nuclear Power Plants only?
Individual
Kirit Shah
Ameren
No
This additional statement is not necessary and already covered in R1 with the statement: ‘while maintaining reliable
protection of the BES for all fault conditions.’
Yes
No
This requirement is redundant with Standards FAC-008-1 and FAC-009-1. The existing standards already cover ratings
methodologies and reporting of facility ratings to the appropriate entities. In addition, these two standards already require
consideration of relaying equipment as one component in developing ratings methodologies and in reporting of those
ratings.
No
Given that protective relaying equipment is already covered as one component in developing ratings in standards FAC008-1 and FAC-009-1, it is not clear that there is a reliability based need for the information required to be provided in
Requirement R5. Therefore, this requirement should be removed from the proprosed standard.
No
Section 6.2 is unclear and seems arbitrary in the statement ‘if the Regional Entity has indentified either of these Element

types as critical facilities for the purpose of the Compliance registry’. A clear test is lacking.
No
As this requirement is structured, it creates a potential for double jeopardy should one of the other requirements
mentioned (R1 through R5) be violated. This requirement is not needed and should be removed from the proposed
standard.
No
Section 1.6 is contrary to section 2.0 and seems arbitrary. Why is a communication system for a current-based scheme
treated to a higher standard than other communications scheme? The communications scheme reliability is covered
through the maintenance and misoperations analysis standards.
No
Criterion B1, which has been modified to encompass only flowgates which have been included to address long-term
reliability concerns, while a step in the right direction, does not go far enough. Because flowgates are primarily utilized to
manage congestion and assist in the process of transmission service sales, rather than investigate reliability issues more
appropriately conducted via study work covered under the TPL standards, this criteria should be eliminated. Criterion B4
as worded still exceeds the requirements of Reliability Standard TPL-003 by requiring simulating double contingencies
with no operator intervention permitted. While such simulation would be done as part of assessment work under TPL-003
for fast-acting contingencies involving multiple circuits, such as Category C1 bus faults, C2 breaker failures, and C5
double-circuit tower outages, such simulations are not necessary under TPL-003 with Category C3 events which consist of
separate Category B events with intervening operator action. Such simulations should not be made necessary as part of
the proposed PRC-023-2 standard. Rather, should the TPL-003 performance requirements not be met for Category C3
contingencies with operator intervention considered, those facilities could be included in the list of facilities specified in
PRC-023-2 Requirement R6.
Individual
Saurabh Saksena
National Grid
No
National Grid seeks clarification on whether criterion 10 requires transformer to have load responsive protection to
protection from mechanical damage. The wording in criterion 10 should be changed to “set transformer fault protection
relay or transmission line relay on transmission line terminated with only a transformer.” For example, is this criteria
requiring that a transformer with only differential protection and no other load responsive remote protection be mitigated
with additional load responsive protection?
No
National Grid seeks clarification on what is the expectation for verifying that the out-of-step blocking elements allow
tripping of phase protection relays for faults that occur during the loading conditions used to verify transmission line relay
loadability? It would be costly and time consuming to verify this. To comply with this requirement, utilities may have to
remove OOS protections all together.
Yes
Yes
Yes
Yes
Yes
No
1. As per Section 4.2.3 (also included as bullet point 2 of Applicable circuits in Attachment B) "Transmission Lines
operated below 100 kV that Regional Entities have identified as critical facilities for the purposes of the Compliance
Registry and the Planning Coordinator has determined are required to comply with this standard." National Grid believes
that voltage levels less than 100 kV are outside NERC's jurisdiction and hence, requirements related to sub 100 kV levels
should not be part of NERC standards. 2. National Grid recommends a provision in the standard which allows entities an
option to 1. Either comply with standard for all applicable elements or 2. Apply the methodology as stated in Attachment B.
The rationale is that entities that choose to comply with PRC-023 for all applicable elements should be recognized and
should be exempted from complying with the methodology in Attachment B. 3. Requirement R6 of the proposed standard
requires entities to apply criteria in Attachment B and conduct assessments with no more than 15 months between
assessments to determine which transmission elements must comply with this standard. TPL standard which is
considered to be the primary standard dealing with designing and planning of the system allows an interim assessment to
rely on previous years simulations and does not mandate a stringent 15 month period between assessments. National
Grid believes that an auxiliary PRC-023 standard should not present more stringent requirements than the primary TPL
standard and recommends to remove the "15 month between assessments" requirement.
Individual
Jeff Billo
ERCOT ISO
Yes

Yes
No
It is not clear what the Planning Coordinator and Reliability Coordinator is supposed to do with this information.
No
No
ERCOT ISO is unclear, as to what is meant by the reference to the Compliance Registry. Additionally, ERCOT ISO feels
the Regional Entities are not the appropriate entities to declare which elements (below 100kV) should be considered
critical. For 6.2 and Attachment B, ERCOT ISO suggests completely removing the existing language pertaining to facilities
operated below 100kV.
Yes
Yes
No
In regards to criteria B1, the Texas Interconnection does not have comparable monitored elements. All transmission
elements are treated and monitored equally in ERCOT at this time. The only exception to this is IROLs which are already
covered in criteria B2. Therefore, ERCOT ISO suggests removing the reference to the Texas Interconnection in criteria
B1. In regards to criteria B3, the Planning Coordinator does not necessarily know the circuit paths for off-site power for
nuclear plants. The Transmission Owners would be better able to identify these circuits. ERCOT ISO suggests moving this
criteria into section 4.2 (Applicability, Facilities). ERCOT ISO also suggests revising the language so that it does not state
that a “circuit must comply with the standard” since it is an entity that must comply with the standard. ERCOT ISO
suggests replacing this language with “circuit will be applicable to this standard” throughout Attachment B.
Individual
Terry Harbour
MidAmerican Energy
Yes
Yes
No
I don't believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission line’s highest
seasonal 15 minute rating does not equate to a line that will trip before the operator has time to intervene. It does not
mean the line will trip in 15 minutes. In fact, the operator should be taking action well in advance of reaching a 15 minute
limit and the operator is likely only using the 15 minute rating in extreme circumstances. Furthermore, PRC-023-2 R3 and
R4 are duplicative of FAC-008-1 and FAC-009-1. FAC-008-1 and FAC-009-1 already collectively require the Transmission
Owner and Generator Owner to establish a facilities ratings methodology, rate its facilities consistent with its methodology
and to communicate those ratings and methodology to its Planning Coordinator, Reliability Coordinator and Transmission
Operator. More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to consider relay
protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings including those
limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed. We assume the drafting team must be aware
of these FAC standard requirements because they did not even require reporting to the Reliability Coordinator, Planning
Coordinator and Transmission Operator of those circuits that are actually limited by the relay per criterion 12. We agree
that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the Transmission Owner and
Generator Owner to communicate these relay limited circuits and that no additional requirements are necessary.
No
While we don’t necessarily have an issue with the equipment owner communicating these relay limited circuits to the
Regional Entities, we don’t believe this is needed for reliability and therefore it should not be included in the reliability
standard. Given that it is unclear what the information will even be used for, if it will be needed long-term, and that it is
likely will not change much, if at all, from year to year, we believe a data request through NERC’s Rules of Procedure
section 1600 would be more appropriate. In that way, we don’t have to modify the standard later when NERC and the
Regions determine they don’t need the data annually.
No
Sections 4.2.2, 4.2.3, 4.2.6, R6, and Attachment B needs to be modified with a superior alternative than the FERC
recommendation to assign the PC the responsibility to determine a sub-200 kV critical facility test. NERC needs to reassign this to the Transmission Owners and Operators as the entities that properly perform transmission planning
analysis. The PC's aren't the proper entities that understand and perform the proper analyses. Therefore the superior
alternative is to re-assign the responsibility to the party that understand what is truly critical and why. At a minimum
Transmission Owners and / or Operators should be added to ensure that the entities that best understand the operation of
the electric grid. It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has
identified that are below 100 kV that are part of the Bulk Electric System. This information is not readily available and there
is no requirement for the Regional Entity to communicate it to them. Thus, inaction by the auditor (i.e. Regional Entity)
could actually cause the Planning Coordinator to violate this requirement. This is clearly a conflict of interest. Why does
the Planning Coordinator need to identify which circuits are identified per criteria B4? There is no justification given for this
need and there is nothing else that appears to require action as a result of this information. Thus, it is purely administrative
and should be removed. Registered entities should never be subject to potential sanctions for violations of purely

administrative portions of requirements. Why does the Planning Coordinator need to provide this information to the
Reliability Coordinator? There is nothing for the Reliability Coordinator to do with the information. The Reliability
Coordinator only needs to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1.
No
We do not believe that R7 is needed. The applicability section of the standard is clear that the standard applies to those
circuits identified in R6. This requirement could be construed as potential for double jeopardy because failure to comply
with Requirements 1-5 for represent a violation of both Requirement 7 and Requirement 1-5.
Yes
No
Criterion B1 should be eliminated as there is no technical basis to show that "flowgates" are anything more than a
measure of congestion. The loss or potential loss of a flowgate won't necessarily result in any more or less reliability
impact to the BES than the loss of any other BES element. Therefore a superior criteria for Attachment B is to actually
base critical elements upon the Federal Power Act Section 215 criteria of instability, uncontrolled separation, or cascading,
which is related to the B2 criteria and being an IROL. Measuring the potential exceedance of TPL criteria as written is also
acceptable. MidAmerican notes the NERC Attachment B criteria exceed the FERC directive to follow TPL criteria in Order
729.
Group
IRC Standards Review Committee
Ben Li

purposes and may be temporary to address certain economic conditions. While we appreciate the drafting team’s effort to
refine the flowgate criteria from the last posting, the modifications do not go far enough and still do not reflect the use of
flowgates. NERC’s definition of flowgate includes two components. Let’s focus on the first component which represents
those flowgates defined in the IDC. Because IDC flowgates list is updated monthly and the IDC users can add temporary
flowgates to the IDC at any time, this is an inappropriate list to use. We appreciate the drafting team’s attempt to resolve
this issue by including the caveat “that has been included to address long-term reliability concerns, as confirmed by the
applicable Planning Coordinator.” However, this really only confuses the matter and does not solve it. Reliability
Coordinators add flowgates to manage real-time congestion. Planning Coordinators do not. Per the NERC functional
model, they do not even have a role in deciding which flowgates to add to the IDC. Flowgates are added to the IDC to
mitigate existing, known congestion points not congestion points identified in a long-term planning study that may never
materialize due to changing conditions. Thus, IDC flowgates should be specifically excluded. Now let us focus on the
second component of flowgate. The second component is much like the first component in that is it a mathematical
construct to analyze the impact of power flows on the BES except is not required to be included in the IDC. There is
nothing in the definition of a flowgate to give credence that is represents anything more that point to calculate power flows
and the impact of transactions. Flowgates are primarily used to manage congestion on the system and to sell transmission
system. Because it is convenient to select a group of lines as a proxy to sell transmission service or manage congestion
does not mean that those group of lines represent a reliability issue. Thus, we do not believe any flowgates should be
included in the list. Any true reliability issues can be identified through the TPL studies and those facilities that do not meet
the performance requirements are what should be used. We do not support criterion B4. It exceeds what is required in the
TPL standards and what is required per the reliability directive in Order 729. The TPL standards allow system operator
intervention for category C3 contingencies between the two independent Category B contingencies. This standard should
not exceed those requirements in the TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the relevant
directives regarding the Planning Coordinator test. Paragraph 79 states that the test “must include or be consistent with
the system simulations and assessments that are required by the TPL Reliability Standards and meet the system
performance levels for all Category of Contingencies used in transmission planning.” Paragraph 80 states that “the test
must be consistent with the general reliability principles embedded in the existing series of TPL” standards. Thus,
exceeding the TPL standards could be argued as deviating from the directive. The directive is to be consistent not exceed.
Exceeding the TPL standards is not consistency. In response to comments that did not support this criterion during the
first posting, the standards drafting team responded with “Testing multiple element contingencies while accounting for
system adjustments between each element outage will not yield any facilities to be subject to PRC-023 as long as TPL003 system performance requirements are met.” We think the drafting team missed a basic point about the standard. The
issue is not whether the registered entity develops and documents corrective actions actions plans TPL-003-0a R2 and
R3. The issue is if the system as currently designed meets the performance requirements in TPL-003-0a R1 which allows
for operator interventions on Category C3 contingencies. For those C3 contingencies that don’t currently meet the
performance obligations after operator interventions, the subject facilities would be included PRC-023-2 R6 list of facilities.
Note: CAISO does not sign on to the above comments.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
B1) The NERC book of flowgates for the Eastern Interconnection includes a combination of permanent and temporary
flowgates. This criteria should only use the permanent flowgates and the text should be modified as indicated to reflect
that. Each circuit that is a monitored Element of a permanent flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Element in the
Texas Interconnection or Québec Interconnection, that has been included to address long-term reliability concerns, as
confirmed by the applicable Planning Coordinator. B3) This appears to link to the NUC-001 standard. We would suggest
the following modification: "Each circuit that forms a path (as agreed to by the plant owner and the Transmission Entity) to
supply off-site power to nuclear plants as established in the NPIR for NUC-001." B5) We suggest removing this one as it is
too open ended and open to interpretation as to which additional circuits should be considered. If there are additional
criteria that are determined later that should be included, then we suggest they be added by either a regional standard or
a SAR to modify the NERC standard.

Consideration of Comments on Relay Loadability Order 733 — Project
2010-13
The Relay Loadability Order 733 Drafting Team thanks all commenters who submitted
comments on the proposed second version of the Relay Loadability Standard PRC-023-2
that includes the applicability test in Attachment B. These standards were posted for a 45day public comment period from November 1, 2010 through December 16, 2010. The
stakeholders were asked to provide feedback on the standards through a special Electronic
Comment Form. There were 38 sets of comments, including comments from more than 67
different people from approximately 73 companies representing 9 of the 10 Industry
Segments as shown in the table on the following pages.
In this report, the comments have been organized by question number so that it is easier to
see where there is consensus. The comments can be viewed in their original format on the
following page:

http://www.nerc.com/filez/standards/SAR_Project%20201013_Order%20733%20Relay%20Modifiations.html
Based on stakeholder comments the drafting team incorporated a significant number of
changes to the standard to address many of the issues raised by the commenters and to
fulfill the FERC directives in Order 733. The changes to the standard primarily clarify the
obligations assigned to the entities and do not substantively modify the requirements.
Significant changes include:
Applicability:
•

Modified to separately address the circuits for which Transmission Owners,
Generator Owners, and Distribution Providers must comply with Requirements R1
through R5 versus the circuits to which the Planning Coordinator must apply the
criteria in Attachment B per Requirement R6.

Effective Dates and Retirement Dates:
•

The effective dates were modified to address the timeframe in which Facility
owners must comply with Requirements R1 through R5 when the Planning
Coordinator identifies a circuit for which the Facility owner must comply with the
standard.

•

The implementation timeframe for the circuits identified in PRC-023-2 was
extended to 39 months to provide the Facility owners time to budget, procure, and
install any protection system equipment modifications and for consistency with
PRC-023-1. For circuits already identified and subject to the requirements in PRC023-1, the existing implementation dates will remain in effect.

•

The retirement dates of the corresponding requirements in PRC-023-1 are
addressed in the implementation plan and are based on the specific requirements.

Requirements:
•

Requirement R1: Criterion 10 was modified to provide additional clarity to ensure
that protection settings do not expose transformers to fault level and duration that
exceed their mechanical withstand capability. The drafting team has clarified this
requirement by making it a separate part of criterion 10 and by indicating this

criterion applies to load responsive transformer fault protective relays, if used. A
footnote was added in reference to IEEE C.57-109-1993, which establishes subjectmatter-expert consensus guidance for transformer through-fault-current duration,
and helps clarify the meaning of mechanical withstand capability as used in this
standard.
•

Requirement R5: Registered Entities that set transmission line relays according to
Requirement R1 criterion 12 are required to provide a list of the circuits associated
with those relays to the Regional Entity at least once each calendar year, with no
more than 15 months between reports. The drafting team modified the
requirement to allow that an updated list of the circuits associated with those
relays be provided. The drafting team also added clarification within the
requirement that the purpose is to allow the ERO to compile a list of all circuits that
have protective relay settings that limit circuit capability.

•

Requirement R6: Significant modification of this requirement was made to avoid
redundancy with other sections of this standard and to improve the clarity of the
requirement. References made to the Statement of Compliance Registry were
replaced with the phrase “that are included on a critical facilities list defined by the
Regional Entity.” The drafting team believes that to maintain consistency with the
NERC Statement of Compliance Registry Criteria, should the Regional Entity
develop a critical facilities list for application of the Compliance Registry Criteria,
the Planning Coordinator would have to apply the criteria in Attachment B to
determine for which of the circuits on the list the applicable entities must comply
with the standard.

•

Requirement R7: Requirement R7 was deleted to remove the double jeopardy
concern between Requirements R1 through R5 and Requirement R7. The intent of
R7 has been incorporated into the Effective Dates section, which has been modified
to address the timeframe in which Facility owners must comply with Requirements
R1 through R5 when the Planning Coordinator identifies a circuit for which the
Facility owner must comply with the standard.

Measures:
•

The Measures for each requirement were updated accordingly to reflect the
changes in the requirement.

VRFs and VSLs:
•

The VRFs and VSLs for each requirement were updated accordingly to reflect the
changes in the requirement.

Attachment B:
•

Significant modifications were made to Attachment B to help clarify the purpose
and understanding of the requirements of this standard and the applicability of the
criteria identified in Attachment B. The circuits to be evaluated and the criteria
used to determine applicability to the PRC-023-2 standard were changed to clarify
the requirements and to address the concerns raised by the stakeholders.

The drafting team strived to address and resolve all of the issues raised by the
stakeholders. A number of comments were not incorporated because the drafting team
believes they are not consistent with the reliability objectives of this standard. Other issues
or suggested modifications were not implemented at this time, as it was felt that the next
revision of the standard may be the best venue for such changes. Among these minority
issues are the following:

•

Expanding the purpose statement of the standard to include the need for relay
settings to be shared and available

•

Periodicity of data submittal and retention

•

Gradations for VSLs in requirements other than R6, and following the NERC
guidelines for these gradations

•

Clarification and consistency among the statement of the requirements that may
better reflect the intention or purpose of each

•

Assorted suggestions for various proposed changes that were relative to approved
content of PRC-023-1

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1

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

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Index to Questions, Comments, and Responses
1.

Requirement R1 defines the criteria for any specific circuit terminal to prevent its phase protective
relay settings from limiting transmission system loadability while maintaining reliable protection of
the BES for all fault conditions. Criterion 10 of Requirement R1 was modified to ensure that
protection settings do not expose transformers to fault level and duration that exceeds their
mechanical withstand capability. Do you agree with the modification to criterion 10 in Requirement
R1? If not, please explain and provide specific suggestions for improvement. ......................... 11

Requirement R2 requires the evaluation of out-of-step blocking schemes to verify that the out-ofstep blocking elements allow tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per Requirement R1. Note this
new Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners,
and Distribution Providers; it only explicitly states in PRC-023-2 an obligation that presently is
included in PRC-023 - Attachment A, section 2 of PRC-023-1. Do you agree with Requirement R2?
If not, please explain and provide specific suggestions for improvement. ............................... 25

Requirement R4 requires the Registered Entities that choose to use Requirement R1 criterion 2 as
the basis for verifying transmission line relay loadability to provide the Planning Coordinator,
Transmission Operator, and Reliability Coordinator with a list of facilities associated with those
transmission line relays at least once each calendar year, with no more than 15 months between
reports. Do you agree with Requirement R4? If not, please explain and provide specific suggestions
for improvement. .................................................................................................. 30

Requirement R5 requires the Registered Entities that set transmission line relays according to
Requirement R1 criterion 12 to provide a list of the facilities associated with those relays to the
Regional Entity at least once each calendar year, with no more than 15 months between reports. Do
you agree with Requirement R5? If not, please explain and provide specific suggestions for
improvement. ...................................................................................................... 41

Requirement R6 requires each Planning Coordinator to apply the criteria in Attachment B to
determine which transmission Elements must comply with this standard. Do you agree with the
requirement included in Requirement R6? If not, please explain and provide specific suggestions for
improvement. ...................................................................................................... 50

Requirement R7 requires the Registered Entities to implement Requirement R1, Requirement R2,
Requirement R3, Requirement R4, and Requirement R5 for each facility that the Planning
Coordinator added to the list of facilities that must comply with this standard (per Requirement R6)
by certain dates following notification by the Planning Coordinator. Do you agree with Requirement
R7? If not, please explain and provide specific suggestions for improvement. ......................... 64

PRC-023 - Attachment A, section 1.6 has been revised to avoid unintended negative impact on
reliability associated with referring to “Protective functions that supervise operation of other
protective functions.” Section 1.6 has been revised to “Supervisory elements associated with
current-based, communication-assisted schemes where the scheme is capable of tripping for loss of
communications” to be more specific to the concern stated in Order No. 733. Do you agree that this
is an equally efficient and effective method of meeting this directive? If not, please explain and
provide specific suggestions for improvement. .............................................................. 71

Attachment B contains the test that the Planning Coordinators must use to determine which
transmission elements (transmission lines operated below 200 kV and transformers with low voltage
terminals connected below 200 kV) must comply with this standard. Do you agree that the method
proposed in Attachment B is a technically sound approach? If not, please explain and provide
specific suggestions for improvement. ........................................................................ 76

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

Mike Garton

Additional Member

Electric Market Policy

Additional Organization

Dominon Resources Services, Inc. MRO

5, 6

2. Louis Slade

Dominion Resources Services, Inc. SERC

5, 6

3. John Loftis

Dominion Virginia Power

1, 3

Group

David K Thorne

Region Segment Selection

1. Michael Gildea

SERC

Potomac Holdings Inc & Affiliates

Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley

RFC

2. Alvin Depew

RFC

3. Bob Reuter

Pepco LSE

RFC

4. Mike Mayer

DPL LSE

RFC

5. Jim Petrella

ACE LSE

RFC

Group

Guy Zito

Additional Member

January 24, 2011

Northeast Power Coordinating Council
Additional Organization

Region Segment Selection

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. Al Adamson

New York State Reliability Council, LLC NPCC 10

2. Gregory Campoli

New York Independent System Operator NPCC 2

3. Michael Schiavone

National Grid

NPCC 1

4. Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

5. Dean Ellis

Dynegy Generation

NPCC 5

6. Brian Evans-Mongeon Utility Services

Ontario Power Generation Incorporated NPCC 5

8. Randy MacDonald

New Brunswick System Operator

NPCC 2

9. Michael R. Lombardi

Northeast Utilities

NPCC 1

10. Kurtis Chong

Independent Electicity System Operator NPCC 2

11. Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

12. Kathleen Goodman

ISO - New England

NPCC 2

13. Mike Garton

Dominion Resources Services, Inc.

NPCC 5

14. Chantel Haswell

FPL Group, Inc.

NPCC 5

15. David Kiguel

Hydro One Networks Inc.

NPCC 1

16. Bruce Metruck

New York Power Authority

NPCC 6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

18. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

19. Robert Pellegrini

The United Illuminating Company

NPCC 1

20. Saurabh Saksena

National Grid

NPCC 1

Group

Steve Alexanderson

NPCC 8

7. Brian L. Gooder

Pacific Northwest Small Public Power Utility
Comment Group

Additional Member Additional Organization Region Segment Selection
1. Russell Noble

Group

Cowlitz County PUD No. 1 WECC 3, 4, 5

Bill Middaugh

Tri-State G & T System Protection

Additional Member Additional Organization Region Segment Selection
1. Jim Pearsall

TSGT

January 24, 2011

WECC 1, 3, 5, 6

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2. Gary Preslan

TSGT

WECC 1, 3, 5, 6

3. LeRoy Martinez

TSGT

WECC 1, 3, 5, 6

4. Matthew Leyba

TSGT

WECC 1, 3, 5, 6

Group

Jason Marshall

Midwest ISO Standards Collaborators

Additional Member Additional Organization Region Segment Selection
1. Terry Harbour

Midamerican Energy

MRO

2. Jim Cyrulewski

JDRJC Associates, LLC RFC

3. Barb Kedrowski

Wisconsin Electric

3, 4, 5

Group

RFC

Carol Gerou

Additional Member

MRO's NERC Standards Review
Subcommittee

Additional Organization

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

5. Jodi Jenson

Western Area Power Administration

MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

7. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

11. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

12. Scott Nickels

Rochester Public Utilties

MRO

13. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

14. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

Group

Terry L. Blackwell

January 24, 2011

Santee Cooper

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member Additional Organization

Region

Rene' Free

Santee Cooper SERC

Bridget Coffman

Santee Cooper SERC

Vicky Budreau

Santee Coope SERC

Group

Denise Koehn

Bonneville Power Administration

Additional Member Additional Organization

Region

BPA, Transmission, SPC Technical Svcs WECC

Chuck Matthews

BPA, Transmission Planning

Doug Hohlbaugh

FirstEnergy

Additional Member Additional Organization Region

Sam Ciccone

RFC

1, 3, 4, 5, 6

Jim Detweiler

RFC

Jim Huber

RFC

Larry Wilson

RFC

Group

Ben Li

Segment
Selection

11.

Segment
Selection

Dean Bender

Group

10.

Segment
Selection

IRC Standards Review Committee

Additional Member Additional Organization Region Segment Selection
1. Bill Phillips

MISO

MRO

2. Patrick Brown

PJM

RFC

3. Steve Myers

ERCOT

ERCOT 2

4. Greg Van Pelt

CAISO

WECC 2

5. Matt Goldberg

ISO-NE

NPCC

6. Mark Thompson

AESO

WECC 2

7. Charles Yeung

SPP

8. James Castle

NYISO

NPCC

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Joshua Wooten

Tennessee Valley Authority

13.

Individual

Bruce Metruck

New York Power Authority

14.

Individual

Joe Petaski

Manitoba Hydro

15.

Individual

Mace Hunter

Lakeland Electric

Individual

Joe O'Brien for Tom
Nappi

NIPSCO

17.

Individual

Nicholas Klemm

Western Area Power Administration

18.

Individual

Richard Burt

Minnkota Power Cooperative, Inc.

19.

Individual

Kathleen Goodman

ISO New England Inc.

20.

Individual

Greg Rowland

Duke Energy

21.

Individual

Tim Hinken

Kansas City Power & Light

22.

Individual

Andrew Pusztai

American Transmission Company

23.

Individual

David Burke

Orange and Rockland Utilities, Inc.

Individual

J. S. Stonecipher, PE

City of Jacksonville Beach, FL dba/Beaches
Energy Services

Individual

Thad K. Ness

American Electric Power

25.

January 24, 2011

Individual

24.

12.

16.

X
X

X
X
X

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

26.

Individual

Steve Wadas

Nebraska Public Power District

27.

Individual

Joe Knight

Great River Energy

28.

Individual

Dan Rochester

Independent Electricity System Operator

29.

Individual

Michael R. Lombardi

Northeast Utilities

30.

Individual

Armin Klusman

CenterPoint Energy

31.

Individual

Gregory Campoli

New York Independent System Operator

32.

Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

33.

Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

34.

Individual

Kirit Shah

Ameren

35.

Individual

Saurabh Saksena

National Grid

36.

Individual

Jeff Billo

ERCOT ISO

37.

Individual

Terry Harbour

MidAmerican Energy

38.

Individual

Alice Ireland

Xcel Energy

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

1. Requirement R1 defines the criteria for any specific circuit terminal to prevent its phase protective relay settings from limiting transmission
system loadability while maintaining reliable protection of the BES for all fault conditions. Criterion 10 of Requirement R1 was modified to
ensure that protection settings do not expose transformers to fault level and duration that exceeds their mechanical withstand capability. Do
you agree with the modification to criterion 10 in Requirement R1? If not, please explain and provide specific suggestions for improvement.
Summary Consideration: In response to Question 1, stakeholders who responded to this question were fairly evenly divided
– where about half agreed with Requirement R1 and about half disagreed with the proposed requirement. Aside from the
typographical error in Requirement R1, criterion 9, criteria 10 and 11 received the majority of the comments. Criterion 10 has
been modified by the drafting team in response to the respondents’ comments to provide additional clarity to the requirement.
A footnote has also been added in reference to IEEE C.57-109-1993, which establishes subject-matter-expert consensus
guidance for transformer through-fault-current duration, and helps clarify the meaning of mechanical withstand capability as
used in this standard. The drafting team also clarified that criterion 10 addresses fault protection relays and their response to
load, and criterion 11 explicitly addresses thermal overload protection. The scope of PRC-023-2 was to address the directives
provided by FERC in Order 733, and the drafting team deliberately limited the scope of changes it made to this standard to
address those directives.

Organization

Yes or No

Electric Market Policy

Yes

Potomac Holdings Inc & Affiliates

Yes

Question 1 Comment

Please note that a typographical error exists in Requirement R1 Criterion 9. The sentence should end with
the phrase “flow from the load to the system under any system configuration”. The words load and system
have been inadvertently omitted in both this draft and the previous draft.

Response: Thank you for your comment.
The text of the standard has been corrected.
Northeast Power Coordinating
Council

1) Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection
to protect from mechanical damage, either from internal faults, or through faults. If load responsive
protection for the transformer element does not presently exist, i.e. only differential protection exists for
the transformer element, will load responsive transformer protection have to be added to comply with this
criterion?
2) The wording in criterion 10 should be changed to “Set transformer fault protection relays or transmission
line relays on transmission lines terminated only with a transformer to .......”
3) Is this criteria requiring that a transformer with only differential protection and no other load responsive

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
remote protection be supplemented additional load responsive protection?
4) The loading on phase angle regulators, and series reactors should be considered and mentioned.
5) Also, there appears to be words missing in criterion 9 of R1: “the maximum current flow from the ? to the
? under any system configuration.” From the NERC Webinar on 11/23/10 the intention was to address the
possible locations where phase protection for the transformer could exist and not imply that this protection
was needed at both locations.

Response: Thank you for your comments.
1) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10, if it does exist. The standard has been modified to clarify this point.
2) The drafting team has considered this comment and similar comments and has modified the text of the standard as appropriate.
3) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
4) The drafting team believes that the phase angle regulating transformers are already included in the standard in criteria 10 and 11, and that series reactors are
already included as part of the element in which they are inserted. This comment will be considered further as we prepare future versions of the standard.
5) The text of the standard has been corrected.
Pacific Northwest Small Public
Power Utility Comment Group

1) The comment group finds R1.10 very confusing when attempting to understand it in the context of IEEE
C57.109-1993. C57.109 identifies a solid curve as the thermal damage curve, while a dotted dog leg is
the mechanical damage curve. Generally the dog leg is only considered for those class II and III
transformers subjected to frequent through faults and all class IV transformers. Is the intent of the SDT to
require this level of protection for all transformers regardless of through fault frequency and/or transformer
class? If the SDT really meant to protect transformers from thermal or combination damage, please note
that it is not possible to completely protect transformers from the thermal damage of low current long
duration faults while still complying with the 150% of maximum rating. The thermal damage curve extends
down to twice the base current. A footnote in C57.109 states that base current is established from the
lowest nameplate kVA rating. A typical transformer with two stages of cooling will have a high nameplate
rating of 1.67 times this base rating. The first bullet of R1.10 states affected entities must allow 1.5 times
the maximum, so we are up to 2.5 times the base rating. Since we must allow this much without tripping,
the relay must be set even higher. 1.2 times would be a secure margin, so the relay is set to pickup at 3
times the base rating. This setting would of course violate the first part of R1 criterion 10 because the
transformer’s fault capability would be exceeded for faults between 2 and 3 times the base rating.
2) We also note that criterion 11 is apparently an exception to criterion 10, but this is not altogether clear

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
since 10 is for fault protection while 11 is for overload protection. Please rewrite this (these) criterion
(criteria) to clarify the SDT’s intent(s).

Response: Thank you for your comments.
1) The drafting team has clarified this requirement by making it a separate part of criterion 10 and by indicating this criterion applies to load responsive
transformer fault protective relays, if used. A footnote has been added to criterion 10 to clarify this requirement is based on the “dotted line” in IEEE C57.1091993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team intended this criterion to apply
to mechanical withstand capability for through faults. Coordination for transformer thermal protection is covered in criterion 11.
2) Criterion 10 and criterion 11 are meant to address separate applications. Criterion 10 addresses fault protection relays and their response to load; criterion 11
explicitly addresses thermal overload protection.
Tri-State G & T System
Protection

There can be cases where the transformer withstand capability will be exceeded if 150% of the applicable
maximum transformer rating is used for the pickup of overcurrent relays. The requirement cannot then be
met if no transformer emergency rating is established. Modify to indicate that if the loading requirement
violates the protection requirement, then the protection requirement should be used while allowing the
maximum loading possible without violating the protection requirement.

Response: Thank you for your comments.
The drafting team has clarified this requirement by making it a separate part of criterion 10 and by indicating this criterion applies to load responsive
transformer fault protective relays, if used. A footnote has been added to criterion 10 to clarify this requirement is based on the “dotted line” in IEEE C57.1091993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team notes that 150 percent of a
typical maximum transformer nameplate rating is on the order of 250 percent (150 percent x 1.67) of the base nameplate rating. The vertical portion of the
mechanical withstand curve is defined by 1/(2xZt), which for a transformer with 12 percent impedance is approximately 400 percent of the nameplate base
rating, allowing protection to be set above the loadability requirement in criterion 10 and below the transformer mechanical withstand curve.
For cases where transformer overload protection is applied and the protection cannot be set above the loadability requirement in criterion 11 and below the
thermal withstand curve, then supervision must be applied as noted in the second bullet of criterion 11.
Midwest ISO Standards
Collaborators

Yes

MRO's NERC Standards Review
Subcommittee

Yes

Santee Cooper

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization
Bonneville Power Administration

January 24, 2011

Yes or No

Question 1 Comment

BPA believes that FERC does not fully understand how transformers are rated and applied on the Bulk
Electric System. Therefore, we believe the concern they expressed in their NOPR and Order 733 regarding
the reliability of the Bulk Electric System being jeopardized by operating a transformer at 150% of its
nameplate rating is unfounded. In response to FERC’s concern, NERC has modified Criterion 10, which now
has two conflicting requirements-ensuring that there is no operation for one level of load and ensuring that
there is operation for another level of load. In some cases, these two load levels overlap and both
requirements cannot be achieved simultaneously. The requirement in Criterion 10 that the protection settings
do not expose the transformer to fault level and duration that exceeds its mechanical withstand capability is
ambiguous. It is not clear how the mechanical withstand capability is to be determined. IEEE Standard
C57.109 provides recommended transformer through-fault duration limits, but these do not represent the
actual mechanical withstand capability of transformers. IEEE Standard C57.12.00 specifies that transformers
shall be designed and constructed to withstand the mechanical and thermal stresses produced by a fault
limited only by the transformer impedance, or for category III and IV transformers, transformer impedance
plus system impedance, for a duration of two seconds. However, the standard specifies that for currents
between rated current and maximum short-circuit current the allowable time duration should be obtained by
consulting the manufacturer. These standards do not clearly indicate what the mechanical withstand
capability of transformers are. Certainly, for many existing transformers, there is no available manufacturer’s
data for this either, and it is unclear how to comply with Criterion 10. BPA feels this is too ambiguous and
exposes entities to an unnecessary risk of possibly being sanctioned based on the judgment of an auditor.
BPA believes that FERC’s concern about transformer damage at the loading levels addressed by this
standard is unfounded and contradictory to the purpose of this standard. The purpose of PRC-023 is to
prevent automatic relay operations--which could cause cascading outages and quickly deteriorate the
reliability of the BES--during severe system loading conditions. Under these loading conditions it is desirable
that system operators have time to take corrective action to mitigate system problems before automatic relay
operations accelerate the problem into a blackout. IEEE Standard C57.109 indicates that transformers can
sustain 200% of rated load for at least thirty minutes. If relays are set to operate in this range, they are at risk
of tripping a transformer under emergency loading situations, which exasperates the very problem that PRC023 is attempting to eliminate. Most utilities have developed emergency ratings for their transformers. When
a transformer load exceeds a predetermined level, the system operators are alarmed so that they can take
appropriate action. During stressed system conditions, allowing a critical transformer to operate up to these
emergency ratings could prevent a blackout. Conversely, requiring relays to be set in this range could result
in the automatic loss of critical transformers, thereby accelerating the collapse of the bulk electric system. The
ability of transformers to carry load without thermal damage or with acceptable levels of loss of life has been
under study for many decades. There are many variables, such as ambient temperature, duty cycle,
acceptable loss of life, etc., that determine the load and duration that a transformer is capable of. It has been
addressed in transformer design and relay protection standards. Many utilities have made considerable
efforts to determine the appropriate levels of emergency loading for their transformers. The mechanical

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
withstand capability of a transformer is not the relevant factor at the load levels addressed by PRC-023. BPA
is concerned that we might be on the verge of superseding these many decades of research and experience
with a poorly written, ambiguous, and inapplicable requirement because of the misunderstanding of the FERC
commissioners. BPA suggests that NERC resist FERC’s demands for setting relays to operate within the
emergency operating capabilities of transformers. Additionally, BPA believes that there is no reason for FERC
to be concerned with transformer overload protection. There is not a widespread problem with transformers
being overloaded, and placing requirements on the industry for transformer protection results in an increased
burden and expense to the industry with no resulting benefits. The subject of transformer loading has gained
FERC’s attention only as a result of its inclusion in PRC-023, and is not a problem for the BES-mostly
because the industry has done the opposite of what FERC is now asking and not set transformer relays to
operate in the emergency loading region. If transformer protection were an issue, it would be worthy of an
individual standard, separate from PRC-023, because it is too complex to address in a short paragraph such
as Criterion 10.Finally, BPA believes that Requirement 1 is unclear. It states that each TO, GO, and DP shall
use any one of the 13 criteria for any specific circuit terminal to prevent its phase protective relays from
limiting transmission loadability. Does this mean that the requirements of Criterion 10 only apply if Criterion
10 is used as the basis for justifying the relay settings of a terminal? If the relay settings for a transformerterminated line are justified by one of the other criteria, say Criterion 1, is an entity allowed to ignore the
requirements of Criterion 10 for the transformer overcurrent relays? Are transformer relays for transformers
that aren’t part of a transformer-terminated line subject to Criterion 10?BPA recommends that the words “such
that the protection settings do not expose the transformer to fault level and duration that exceeds its
mechanical withstand capability” be removed from Criterion 10. In addition, if all transformer overcurrent
relays-not just those for transformer-terminated lines-are subject to the requirements of Criterion 10 (as
suggested by Attachment A), they need to be addressed in a separate requirement because the 13 criteria of
Requirement 1 are not necessarily mandatory.

Response: Thank you for your comments.
The drafting team has clarified this requirement by making it a separate part of criterion 10 and by indicating this criterion applies to load responsive transformer
fault protective relays, if used. A footnote has been added to criterion 10 to clarify this requirement is based on the “dotted line” in IEEE C57.109-1993 – IEEE
Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team notes that 150 percent of a typical maximum
transformer nameplate rating is on the order of 250 percent (150 percent x 1.67) of the base nameplate rating. The vertical portion of the mechanical withstand
curve is defined by 1/(2xZt), which for a transformer with 12 percent impedance is approximately 400 percent of the nameplate base rating, allowing protection to
be set above the loadability requirement in criterion 10 and below the transformer mechanical withstand curve.
For cases where transformer overload protection is applied and the protection cannot be set above the loadability requirement in criterion 11 and below the
thermal withstand curve, then supervision must be applied as noted in the second bullet of criterion 11.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization
FirstEnergy

Yes or No

Question 1 Comment

1) Criterion 10 does not take bidirectional load flow into consideration which could compromise the entity’s
ability to provide backup protection for the transmission system. We suggest the following wording for
criterion 10: “Set transformer fault protection relays and transmission line relays on transmission lines
terminated only with a transformer such that the protection settings do not expose the transformer to fault
level and duration that exceeds its mechanical withstand capability and so that the relays do not operate
at or below the greater of:ï‚§ 150% of the applicable maximum transformer nameplate rating (expressed
in amperes), including the forced cooled ratings corresponding to all installed supplemental cooling
equipment for load flow from the normal source side to the normal load side.ï‚§ 115% of the highest
operator established emergency transformer rating for load flow from the normal source side to the
normal load side.ï‚§ 115% of the maximum current flow from the normal load side to the normal source
side under any system configuration.”
2) We also ask that the team consider similar wording be added to Criterion 11 as suggested above for
consistency with Criterion 10.
3) Criterion 9 seems to be missing some words in the phrase “flow from the to the under any system
configuration”. It appears this should say “from the load to the system under any system configuration.”

Response: Thank you for your comments.
1) The issue of bidirectional flow is outside the scope of this project and will be considered as part of future enhancements to the standard.
2) The issue of bidirectional flow is outside the scope of this project and will be considered as part of future enhancements to the standard.
3) The text of the standard has been corrected.
Tennessee Valley Authority

Yes

New York Power Authority

1) Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection
to protect from mechanical damage, either from internal faults, or through faults. If load responsive
protection for the transformer element does not presently exist (i.e., only differential protection exists for
the transformer element) will load responsive transformer protection have to be added to comply with this
criterion?
2) The wording in criterion 10 should be changed to “Set transformer fault protection relays or transmission
line relays on transmission lines terminated only with a transformer to .......”
3) Is this criterion requiring that a transformer with only differential protection and no other load responsive
remote protection be supplemented with additional load responsive protection?

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
4) The loading on phase angle regulators, and series reactors should be considered and mentioned.
5) Also, there appears to be words missing in criterion 9 of R1: “the maximum current flow from the ? to the
? under any system configuration.” From the NERC Webinar on 11/23/10 the intention was to address the
possible locations where phase protection for the transformer could exist and not imply that this protection
was needed at both locations.

Response: Thank you for your comments.
1) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
2) The drafting team has considered this comment and similar comments and has modified the text of the standard.
3) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
4) The drafting team believes that the phase angle regulating transformers are already included in the standard in criteria 10 and 11, and that series reactors are
already included as part of the element in which they are inserted. This comment will be considered as we prepare future versions of the standard.
5) The text of the standard has been corrected.
Manitoba Hydro

Yes

Lakeland Electric

Yes

NIPSCO

The mechanical withstand is not an appropriate value because every fault event will reduce the life of a
transformer. Setting the limit at the maximum expected one-time event limit will prematurely destroy the
transformers. Maybe a sliding scale would be better with each transformer owner to decided how much
expected life to risk for faults.

Response: Thank you for your comments.
IEEE C57.109-1993, IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, establishes subject-matter-expert consensus guidance for
transformer through-fault-current duration. The mechanical withstand characteristic is discussed in IEEE C57.109-1993 relative to faults that will occur frequently.
Criterion 10 is consistent with IEEE C57.109-1993.
Western Area Power
Administration

January 24, 2011

1) Established industry standards and practices have defined the mechanical damage portion of the
transformer curve to apply for repetitive faults. Neither FERC nor NERC should have the right to
contradict established technical practices. Entities should be able to coordination protection systems

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
taking into account protection and controls (e.g. the use of lockouts) which prevent repetitive exposure to
mechanical damage thereby alleviating cumulative effects.
2) Also, it is not clear what "transmission line relays on transmission lines terminated only with a
transformer..." applies to. Need clarification.

Response: Thank you for your comments.
1) IEEE C57.109-1993, IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, establishes subject-matter-expert consensus guidance for
transformer through-fault-current duration. The mechanical withstand characteristic is discussed in IEEE C57.109-1993 relative to faults that will occur
frequently. Criterion 10 is consistent with IEEE C57.109-1993.
2) The drafting team believes that this comment addresses approved content in PRC-023-1, and is therefore outside the scope of this project.
Minnkota Power Cooperative,
Inc.

Yes

Duke Energy

Yes

Kansas City Power & Light

Yes

American Transmission
Company

Yes

Orange and Rockland Utilities,
Inc.

1) Clarification is needed on whether criterion 10 requires a transformer to have load responsive protection
to protect from mechanical damage.
2) The wording in criterion 10 should be changed to “set transformer fault protection relay or transmission
line relay on transmission line terminated with only a transformer.”
3) Is this criterion requiring that a transformer with only differential protection and no other load responsive
remote protection be mitigated with additional load responsive protection?
4) The loading on phase angle regulators, and series reactors should also be considered and mentioned.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment

2) The drafting team has considered this comment and similar comments and has modified the text of the standard.
3) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
4) The drafting team believes that the phase angle regulating transformers are already included in the standard in criteria 10 and 11, and that series reactors are
already included as part of the element in which they are inserted. This comment will be considered as we prepare future versions of the standard.
City of Jacksonville Beach, FL
dba/Beaches Energy Services

Yes

However, R1 and R2 have binary VSLs, where they should be percentages of all relays that need to meet the
standard based on statistical sampling.

Response: Thank you for your comment.
The VSLs defined are consistent with the VSLs already approved by FERC in PRC-023-1.
American Electric Power

American Electric Power sees two issues with R1's Criterion 10.
First, transformer "mechanical withstand capability" is undefined, vague, and subject to various
interpretations. The terminology used in this criterion must be more tightly defined to prevent ambiguity or
else referenced to some agreed-upon standard such as IEEE C57.109-1993.
Second, American Electric Power agrees that it is appropriate for the 150% and 115% settings criteria to
apply to line relays terminated only with a transformer. However, Criterion 10 seems to assume that
transmission line relays on transmission lines terminated with a transformer are also typically intended to
protect the transformer. This is not normally or necessarily true. If the line relays are not intended to protect
the transformer and as long as the transformer relaying properly protects the transformer from mechanical
damage, there is no reason for Criterion 10 to apply to the line relays.
To address these two deficiencies in Criterion 10, American Electric Power sets forth the following two-part
replacement language for Criterion 10:10.1 Set transformer fault protection relays such that the protection
settings do not expose the transformer to fault level and duration that exceeds its mechanical withstand
capability as defined by IEEE C57.109-1993 or its successor standard and so that the relays do not operate
at or below the greater of: o 150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed supplemental cooling equipment.
o 115% of the highest operator established emergency transformer rating.10.2 Set transmission line relays
on transmission lines terminated only with a transformer so that the relays do not operate at or below the
greater of: o 150% of the applicable maximum transformer nameplate rating (expressed in amperes),
including the forced cooled ratings corresponding to all installed supplemental cooling equipment. o 115% of
the highest operator established emergency transformer rating. If the transformer fault protection relays on
the line-terminated transformer do not expose the transformer to fault level and duration that exceeds its

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
mechanical withstand capability, then the transmission line relays do not also need to provide the same
protection against transformer mechanical damage.

Response: Thank you for your comments.
The drafting team agrees that mechanical withstand capability requires further clarification and has added a footnote that this requirement is based on the “dotted
line” in IEEE C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4.
The drafting team also agrees that while both the transmission line and transformer fault protection must meet the relay loadability requirement, it is sufficient for
only the transformer fault protection to coordinate with the mechanical withstand capability. The drafting team has clarified this requirement by making it a
separate part of criterion 10 and by indicating this criterion applies to load responsive transformer fault protective relays, if used.
The drafting team believes the modifications address the commenter’s concern, although through different modifications than those recommended by the
commenter.
Nebraska Public Power District

Yes

Great River Energy

Yes

Independent Electricity System
Operator

Response: Thank you for your comment.
1) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
2) The drafting team has considered this comment and similar comments and has modified the text of the standard.
3) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
Northeast Utilities

Further clarification is needed for this criterion.
1) Is it the intention of this criterion that all applicable transformers must have load responsive protection to

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
prevent mechanical damage from a through fault? If load responsive protection for the transformer
element does not presently exist, i.e. only differential protection exists for the transformer element, will
load responsive transformer protection have to be added to comply with this criterion?
2) It is also suggested that R1 Criterion 10 wording be changed to “Set transformer fault protection relays or
transmission line relays on transmission lines terminated only with a transformer to .......” since it appears
from the NERC Webinar on 11/23/10 that the intention was address the possible locations where phase
protection for the transformer could exist and not infer that this protection was needed at both locations.

Response: Thank you for your comments.
1)

2) The drafting team has considered this comment and similar comments and has modified the text of the standard.
New York Independent System
Operator

Yes

Oncor Electric Delivery Company
LLC

In paragraph 209 of Order No 733 it states: Since Requirement R1.10 applies to any topology, it must be
robust enough to address the reliability issues of any topology.
In light of the above statement criterion 10 of Requirement R1 should be modified to read as follows: Set
transformer fault protection relays and transmission line relays used for transformer fault protection such that
the protection settings do not expose the transformer to fault level and duration that exceeds its mechanical
withstand capability and so that the relays do not operate at or below the greater of:
By eliminating the special topology of “transmission lines terminated only with a transformer” from criterion 10
it eliminates any ambiguity that the criterion only applies to special transmission line cases and complies with
the FERC assertion that the Requirement “applies to any topology.”
Oncor like other Transmission Owners provides autotransformer protection from possible thermal damage
due to either prolonged through faults or load with its transformer overload protection relays. Protection of all
autotransformers from fault level and duration that exceeds their mechanical withstand capability is provided
by the redundant phase and ground relay settings of the local zones of protection coupled with local breaker
failure protection. For prolonged faults that are outside the local zones of protection (not threatening damage
to the transformer by exceeding the mechanical withstand capability of the transformer) or where loads
exceed the thermal rating of the transformer the phase and ground transformer overload protection relays
protect the transformer from thermal damage.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
Based on the fact that at many locations a transformer is protected by local Protection Systems from
prolonged “Close in” phase and ground through faults that might be within the fault level and duration that
exceeds their mechanical withstand capability, criterion 11 of Requirement R1 should be modified as follows:
For transformer overload protection relays that do not comply with the loadability or mechanical withstand
capability components of Requirement R1, criterion 10 set the relays according to one of the following: If
transformer protection from fault level and duration that exceeds a transformer’s mechanical withstand
capability is provided by other Protection Systems, set the transformer overload protection settings to not
expose the transformer to current level and duration that exceeds its thermal withstand capability and so that
the relays do not operate at or below the greater of 150% of the applicable maximum transformer nameplate
rating (expressed in amperes), including the forced cooled ratings corresponding to all installed supplemental
cooling equipment or 115% of the highest operator established emergency transformer rating. Set the relays
to allow the transformer to be operated at an overload level of at least 150% of the maximum applicable
nameplate rating, or 115% of the highest operator established emergency transformer rating, whichever is
greater, for at least 15 minutes to provide time for the operator to take controlled action to relieve the
overload. Install supervision for the relays using either a top oil or simulated winding hot spot temperature
element set no less than 100Â° C for the top oil temperature or no less than 140Â° C for the winding hot spot
temperature.
Oncor believes that criterion 10 of Requirement R1 needs to be further modified as stated above to ensure
that it applies to transmission lines of any topology and not just to transmission lines terminated only with a
transformer.
Oncor also feels that modifying criterion 10 of Requirement R1 by adding a requirement to ensure that
protection settings do not expose transformers to fault level and duration requires that, for the reasons stated
above, criterion 11 of Requirement R1 must be modified as noted above.

Response: Thank you for your comments.
Criterion 10 applies to (1) transformers fault protection relays and (2) transmission lines relays applied on transmission lines terminate only with a transformer.
The drafting team notes the first clause of this criterion applies to all transformer configurations. The clause referring to transmission lines terminated only with a
transformer delineates that criterion 10 does not apply to all transmission line relays.
The drafting team has clarified this requirement by making it a separate part of criterion 10 and by indicating this criterion applies to load responsive transformer
fault protective relays, if used. A footnote has been added to criterion 10 to clarify this requirement is based on the “dotted line” in IEEE C57.109-1993 – IEEE
Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team intended this criterion to apply to mechanical
withstand capability for through faults. Coordination for transformer thermal protection is covered in criterion 11.
The drafting team believes that the comments regarding criterion 11 address approved content in PRC-023-1, and is therefore outside the scope of this project.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization
Consolidated Edison Co. of NY,
Inc.

Yes or No
No

Question 1 Comment
1) R1 - Clarification is needed on whether criterion 10 requires a transformer to have load responsive
protection to protect from mechanical damage.
2) The wording in criterion 10 should be changed to “set transformer fault protection relay or transmission
line relay on transmission line terminated with only a transformer.”
3) Is this criterion requiring that a transformer with only differential protection and no other load responsive
remote protection be mitigated with additional load responsive protection?
4) The loading on phase angle regulators, and series reactors should also be considered and mentioned.
5) Also, there appears to be words missing in criterion 9 of R1: “the maximum current flow from the ? to the
? under any system configuration.”

Response: Thank you for your comments.
1) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
2) The drafting team has considered this comment and similar comments and has modified the text of the standard.
3) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
4) The drafting team believes that the phase angle regulating transformers are already included in the standard in criteria 10 and 11, and that series reactors are
already included as part of the element in which they are inserted. This comment will be considered as we prepare future versions of the standard.
5) The text of the standard has been corrected.
Ameren

This additional statement is not necessary and already covered in R1 with the statement: ‘while maintaining
reliable protection of the BES for all fault conditions.’

Response: Thank you for your comment.
While this issue may have been implicitly addressed in Requirement R1, FERC Order 733 has directed that this issue be explicitly addressed in criterion 10.
National Grid

1) National Grid seeks clarification on whether criterion 10 requires transformer to have load responsive
protection to protection from mechanical damage.
2) The wording in criterion 10 should be changed to “set transformer fault protection relay or transmission
line relay on transmission line terminated with only a transformer.”

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 1 Comment
3) For example, is this criteria requiring that a transformer with only differential protection and no other load
responsive remote protection be mitigated with additional load responsive protection?

Yes

MidAmerican Energy

Yes

Xcel Energy

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

2. Requirement R2 requires the evaluation of out-of-step blocking schemes to verify that the out-of-step blocking elements allow tripping of
phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1.
Note this new Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners, and Distribution Providers; it only
explicitly states in PRC-023-2 an obligation that presently is included in PRC-023 - Attachment A, section 2 of PRC-023-1. Do you agree with
Requirement R2? If not, please explain and provide specific suggestions for improvement.
Summary Consideration: In response to Question 2, most stakeholders who responded to this question indicated support for
Requirement R2. The majority of the commenters were seeking clarification on the expected method for verifying that the outof-step blocking elements allow tripping of phase protection relays for faults that occur during the loading conditions used to
verify transmission line relay loadability. They were concerned about the potential for a costly and time consuming method for
this verification. The drafting team has modified the requirement text to provide additional clarification, but it also points out
that this requirement was included in Attachment A of PRC-023-1 and believes that it could be met by performing planning
analyses of the relay settings.

Organization

Yes or No

Electric Market Policy

Yes

Potomac Holdings Inc & Affiliates

Yes

Northeast Power Coordinating
Council

Yes

Pacific Northwest Small Public
Power Utility Comment Group

Yes

Tri-State G & T System
Protection

Yes

MRO's NERC Standards Review
Subcommittee

Yes

Santee Cooper

January 24, 2011

Question 2 Comment

We appreciate the drafting team addressing this issue, and, in general, agree with our understanding of the
intention of this requirement. However, the wording of the section should be a little clearer. Through asking
questions about the intention of these statements, it is our understanding that, as long as the composite
scheme (made up of all the relay elements protecting the transmission line) will still operate for a fault in a
time that is compliant with the TPL standards, that this requirement is met. This may mean that a particular

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 2 Comment
relay element may still be blocked, but there are other relay elements, possibly with a different time delay, that
would still operate in an appropriate amount of time. As long as the total scheme protecting the element in
question still meets all of the TPL and stability requirements for isolating the fault from the system, the
operation of the scheme should be satisfactory. If this is still the intention, then it should be clarified in this
requirement.

Response: Thank you for your comment.
The drafting team has considered this comment and similar comments and has modified the text of the standard.
Bonneville Power Administration

Yes

FirstEnergy

Yes

Tennessee Valley Authority

Yes

New York Power Authority

Yes

Manitoba Hydro

Yes

Lakeland Electric

Yes

NIPSCO

We believe this is already included

Response: Thank you for your comment.
While this issue may have been addressed in Attachment A, FERC Order 733 has directed that this issue be explicitly addressed in a separate requirement.
Western Area Power
Administration

Yes

Minnkota Power Cooperative,
Inc.

Yes

Duke Energy

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Kansas City Power & Light

Yes

American Transmission
Company

Yes

Orange and Rockland Utilities,
Inc.

Question 2 Comment

What is the expectation for verifying that the out-of-step blocking elements allow tripping of phase protection
relays for faults that occur during the loading conditions used to verify transmission line relay loadability? It
would be costly and time consuming to verify this. To comply with this requirement, utilities may have to
remove OOS protections all together. This should be able to be tested during routine trip testing. Between
the trip testing procedures, and relay calibrations this requirement should be satisfied, and easily
documented.

Response: Thank you for your comment.
The drafting team believes that this requirement will be met by a planning analysis of the settings. This is not a new requirement. PRC-023-1 requires, within
Attachment A, that this analysis be done.
City of Jacksonville Beach, FL
dba/Beaches Energy Services

Yes

R1 and R2 have binary VSLs, where they should be percentages of all relays that need to meet the standard
based on statistical sampling. (See previous comment for R1.)

Response: Thank you for your comment.
The VSLs defined are consistent with the VSLs already approved by FERC in PRC-023-1.
American Electric Power

Yes

Nebraska Public Power District

Yes

Great River Energy

Yes

Independent Electricity System
Operator

Yes

Northeast Utilities

January 24, 2011

What is the expectation for verification that the out-of-step blocking elements allow tripping of phase
protection relays for faults that occur during the loading conditions used to verify transmission line relay
loadability? It would be very costly and time consuming to verify proper operation of these blocking schemes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 2 Comment
for all of the various possible fault and loading combination scenarios for each application of this scheme.

Response: Thank you for your comment.
The drafting team believes that this requirement will be met by a planning analysis of the settings. This is not a new requirement. PRC-023-1, within Attachment
A, requires that this analysis be done.
New York Independent System
Operator

No comment from the PC & RC perspective, the TOs are responsible for designing phase protection schemes
appropriate to their systems

Response: Thank you for your comment.
Oncor Electric Delivery Company
LLC

Yes

Consolidated Edison Co. of NY,
Inc.

R2 - What is the expectation for verifying that the out-of-step (OOS) blocking elements allow tripping of phase
protection relays for faults that occur during the loading conditions used to verify transmission line relay
loadability? It would be costly and time consuming to verify this. To comply with this requirement, utilities
may have to remove OOS protections all together.

Response: Thank you for your comment.
The drafting team believes that this requirement will be met by a planning analysis of the settings. This is not a new requirement. PRC-023-1, within Attachment
A, requires that this analysis be done.
Ameren

Yes

National Grid

National Grid seeks clarification on what is the expectation for verifying that the out-of-step blocking elements
allow tripping of phase protection relays for faults that occur during the loading conditions used to verify
transmission line relay loadability? It would be costly and time consuming to verify this. To comply with this
requirement, utilities may have to remove OOS protections all together.

Response: Thank you for your comment.
The drafting team believes that this requirement will be met by a planning analysis of the settings. This is not a new requirement. PRC-023-1, within Attachment
A, requires that this analysis be done.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

ERCOT ISO

Yes

MidAmerican Energy

Yes

Xcel Energy

Yes

January 24, 2011

Question 2 Comment

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

3. Requirement R4 requires the Registered Entities that choose to use Requirement R1 criterion 2 as the basis for verifying transmission line
relay loadability to provide the Planning Coordinator, Transmission Operator, and Reliability Coordinator with a list of facilities associated with
those transmission line relays at least once each calendar year, with no more than 15 months between reports. Do you agree with
Requirement R4? If not, please explain and provide specific suggestions for improvement.
Summary Consideration: In response to Question 3, stakeholders who responded to this question were fairly evenly divided
with about half indicating support for Requirement R4 and about half expressing some disagreement with the proposed
requirement.
A significant number of commenters indicated that they believe PRC-023-2 Requirements R3 and R4 are duplicative of FAC008-1 and FAC-009-1. FAC-008-1 and FAC-009-1 already collectively require the Transmission Owner and Generator Owner to
establish a facilities ratings methodology, rate its facilities consistent with its methodology, and communicate those ratings and
methodology to the Planning Coordinator, Reliability Coordinator and Transmission Operator. The drafting team states that
FAC-008 and FAC-009 do not really address the Requirements stated in R3 and R4. The drafting team clarified that FAC-009
requires the communication of the Facility Rating, whereas PRC-023-2 requires notification when the relay loadability is based
on a 15-minute rating.
Many of the commenters stated that they should only be required to provide the list of facilities with transmission line relays
that use Requirement R1, criterion 2 to the Transmission Operators. The drafting team responded that since the Reliability
Coordinators and Planning Coordinators both use the ratings data as part of their functional responsibilities that data must also
be made available to them.
Many of the commenters were concerned about the proposed effective date for Requirements R4 & R5. The drafting team
responded that since Requirements R4 & R5 only impose a reporting requirement, the shorter period of six months after
regulatory approvals or Board of Trustees adoption is appropriate.
A significant number of the commenters indicated that they don’t understand why a full list of facilities with transmission line
relays that use Requirement R1 criterion 2 must be provided each year. These facilities will not change very often, and a new
list should only be required when a change is made to the existing list. The drafting team considered these comments and
revised Requirements R4 & R5 to require an updated list, and the associated measures have also been revised to indicate that
the updated list may either be a full list or a list of incremental changes to the previous list

Organization
Electric Market Policy

January 24, 2011

Yes or No

Question 3 Comment

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization
Potomac Holdings Inc & Affiliates

Yes or No

Question 3 Comment

Yes

In the SDT’s response “Consideration of Comments on Revisions to Relay Loadability for Order 733 SAR and
an initial set of proposed requirements - Project 2010-13” dated November 1, 2010, the SDT proposed to
establish the effective date for requirements R4 & R5 as “the first day of the first calendar quarter following
24 months after regulatory approvals.” However in the latest draft of the standard the 24 month requirement
was replaced with 6 months. Which is correct?

Response: Thank you for your comment.
The effective date of the standard is the first day of the first calendar quarter following six months after regulatory approvals. Since this is only a reporting
requirement, the drafting team believes that six months is appropriate.
Northeast Power Coordinating
Council

Yes

Pacific Northwest Small Public
Power Utility Comment Group

Yes

Tri-State G & T System
Protection

1) We believe that the list of facilities with transmission line relays that use Requirement R1 criterion 2 needs
to be given only to the Transmission Operators as directed by Paragraph 186 of FERC Order no. 733,
and not also to the Planning Coordinators and Reliability Coordinators.
2) We also believe that an initial submittal is sufficient until any responsible entity begins or stops using that
criterion on any element. Periodic duplicate submittals are unnecessary and unique submittals would
more easily identify the loadability issues that the operators need to consider. The FERC Order did not
require annual submittals.

Response: Thank you for your comments.
1)

Since the Reliability Coordinators and Planning Coordinators both use ratings data as part of their functional responsibilities, the drafting team believes that
the data must be made available to them.

2) The requirement has been revised to require an updated list and the accompanying measure has been modified to indicate that the updated list may either be
a full list or a list of incremental changes to the previous list.
Midwest ISO Standards
Collaborators

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment
circumstances.
Furthermore, PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC-008-1 and FAC009-1 already collectively require the Transmission Owner and Generator Owner to establish a facilities
ratings methodology, rate its facilities consistent with its methodology and to communicate those ratings and
methodology to its Planning Coordinator, Reliability Coordinator and Transmission Operator. More
specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to consider relay
protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed.
We assume the drafting team must be aware of these FAC standard requirements because they did not even
require reporting to the Reliability Coordinator, Planning Coordinator and Transmission Operator of those
circuits that are actually limited by the relay per criterion 12.
We agree that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits and that no additional
requirements are necessary.

Response: Thank you for your comments.
Providing this information to the specified entities addresses the potential for confusion as to the amount of time available to take corrective action.
FAC-008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the relay
loadability is based on a 15-minute rating.
MRO's NERC Standards Review
Subcommittee

We do not believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission
line’s highest seasonal 15 minute rating does not equate to a line that will trip before the operator has time to
intervene. It does not mean the line will trip in 15 minutes. In fact, the operator should be taking action well in
advance of reaching a 15 minute limit and the operator is likely only using the 15 minute rating in extreme
circumstances.
Furthermore, PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC-008-1 and FAC009-1 already collectively require the Transmission Owner and Generator Owner to establish a facilities
ratings methodology, rate its facilities consistent with its methodology and to communicate those ratings and
methodology to its Planning Coordinator, Reliability Coordinator and Transmission Operator. More
specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to consider relay
protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed.
We assume the drafting team must be aware of these FAC standard requirements because they did not even

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment
require reporting to the Reliability Coordinator, Planning Coordinator and Transmission Operator of those
circuits that are actually limited by the relay per criterion 12.
We agree that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits and that no additional
requirements are necessary.

Yes

Bonneville Power Administration

BPA does not understand why a list of such facilities must be provided each year. These facilities will not
change very often, and a new list should only be required when changes are made to the old list. Please
explain why you feel it is necessary.

Yes

IRC Standards Review
Committee

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed.
We assume the drafting team must be aware of these FAC standard requirements because they did not even
require reporting to the Reliability Coordinator, Planning Coordinator and Transmission Operator of those
circuits that are actually limited by the relay per criterion 12.
We agree that FAC-008-1 and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits and that no additional
requirements are necessary.
Note: CAISO does not sign on to the above comments.

Yes

New York Power Authority

Yes

Manitoba Hydro

Yes

Lakeland Electric

Yes

NIPSCO

We're not sure what the value is in this requirement?

Yes

Minnkota Power Cooperative,
Inc.

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Duke Energy

Yes

Kansas City Power & Light

Question 3 Comment

Yes

Orange and Rockland Utilities,
Inc.

Yes

City of Jacksonville Beach, FL

January 24, 2011

No, that is way too frequent. It should be a much longer time criteria, say 5 years, with a requirement that if

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

dba/Beaches Energy Services

Question 3 Comment
there is a CHANGE, the information is sent to the PC, TO and RC.

Response: Thank you for your comment.
The drafting team believes that updates need to be provided annually; the requirement has been revised to require an updated list and the accompanying
measure has been modified to indicate that the updated list may either be a full list or a list of incremental changes to the previous list.
American Electric Power

Yes

Nebraska Public Power District

NERC does not need a separate requirement for TOs, GOs, and DPs to specifically report R1, criterion 2. If
they meet the requirement the line will not trip. If they meet the requirement and the line is overloaded the
operator will receive an alarm and will take action within 15 minutes.

We do not believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission
line’s highest seasonal 15 minute rating does not equate to a line that will trip before the operator has time to
intervene. It does not mean the line will trip in 15 minutes. In fact, the operator should be taking action well in
advance of reaching a 15 minute limit and the operator is likely only using the 15 minute rating in extreme
circumstances. Furthermore, PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC008-1 and FAC-009-1 already collectively require the Transmission Owner and Generator Owner to establish
a facilities ratings methodology, rate its facilities consistent with its methodology and to communicate those
ratings and methodology to its Planning Coordinator, Reliability Coordinator and Transmission Operator.
More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to consider relay
protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed. We assume the
drafting team must be aware of these FAC standard requirements because they did not even require
reporting to the Reliability Coordinator, Planning Coordinator and Transmission Operator of those circuits that
are actually limited by the relay per criterion 12. We agree that FAC-008-1 and FAC-009-1 collectively
establish the necessary requirements to compel the Transmission Owner and Generator Owner to
communicate these relay limited circuits and that no additional requirements are necessary.

Response: Thank you for your comment.
Providing this information to the specified entities addresses the potential for confusion as to the amount of time available to take corrective action.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment

FAC-008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the relay
loadability is based on a 15-minute rating.
Independent Electricity System
Operator

As indicated in our previous comments, the FERC Directive asks for provision of this information to the TOP
only. We question the need to go beyond what’s being asked for in the Directive to require the responsible
entities to provide this information to other entities (PC and RC). If a reliability need is not identified, we
suggest that these two entities be removed from the requirement.

Response: Thank you for your comment.
Since the Reliability Coordinators and Planning Coordinators both use ratings data as part of their functional responsibilities, the drafting team believes that the
data must be made available to them.
Northeast Utilities

Yes

Suggest clarification for Section 4.2.6 be added. That is, our review of the draft indicates that, as its title
implies, this Standard primarily focuses on transmission relaying for lines and transformers. Nowhere does it
mention generation relaying, per se, and the transformer relaying appears to be focused on “transmission”
transformers and other transformers that have bi-directional flow capability. There is one sticking point,
however. Section 4.2.6 seems to muddy the otherwise clear “transmission” directive in that it extends the
applicability to: “4.2.6 Transformers with low voltage terminals connected below 100 kV that Regional Entities
have identified as critical facilities for the purposes of the Compliance Registry and the Planning Coordinator
has determined are required to comply with this standard”. While we believe that this was intended to pertain
to transmission or load-serving transformers, due to ambiguity in the Standard this could be taken to mean
transformers in facilities deemed “material to the reliability of the Bulk Power System.” It could thus be applied
(incorrectly, in our opinion) to generation facilities. We would also question why there would be a concern for
the low voltage side of a GSU. Please clarify Section 4.2.6, as appropriate.

Response: Thank you for your comment.
Transformers with low voltage terminals connected below 100 kV will be subject to the standard as determined by the application of the criteria in Attachment B,
and any relevant responsive relays will need to comply with this standard.
Generator relay loadability issues will be addressed in Phase 2 of Project 2010-13.
CenterPoint Energy

January 24, 2011

CenterPoint Energy disagrees with providing a list to Planning Coordinators, Transmission Operators, and
Reliability Coordinators, as we cannot see any need and do not expect these entities would utilize this
information in any manner.

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment

PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1, and therefore unnecessary. FAC-0081 and FAC-009-1 already collectively require the Transmission Owner and Generator Owner to establish a
facilities ratings methodology, rate its facilities consistent with its methodology and to communicate those
ratings and methodology to its Planning Coordinator, Reliability Coordinator and Transmission Operator.
More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to consider relay
protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays.

Response: Thank you for your comment.
Providing this information to the specified entities addresses the potential for confusion as to the amount of time available to take corrective action.
FAC-008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the relay
loadability is based on a 15-minute rating.
Oncor Electric Delivery Company
LLC

January 24, 2011

Oncor feels that the Requirement R4 is too cumbersome for the Registered Entities who have to, every 12 to
15 months, provide to the Planning Coordinator, Transmission Operator and Reliability Coordinator massive
amounts of information that rarely changes. Also by allowing up to 15 months between reports to the
Planning Coordinator, Transmission Operator and Reliability Coordinator of relay setting changes made by
Registered Entities these Operators and Coordinators are deprived of knowing changes to loading limitations
for up to 15 months. To overcome the problems with Requirement R4 of the present version PRC-023-2
Oncor has two specific suggestions for improvement. First, Requirement R4 should be changed to have a
onetime requirement for Each Transmission Owner, Generator Owner, and Distribution Provider that chooses
to use Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability to provide its
Planning Coordinator, Transmission Operator, and Reliability Coordinator with a list of facilities associated
with those transmission line relays. Second, Requirement R4 should be changed to require Each
Transmission Owner, Generator Owner, and Distribution Provider that chooses to use Requirement R1
criterion 2 as the basis for verifying transmission line relay loadability to provide its Planning Coordinator,
Transmission Operator, and Reliability Coordinator with any changes (additions, deletions or modifications) to
the one time list of facilities associated with those transmission line relays within 30 days changes are made
to list. By using the proposed changes to R4 listed above, the only information that needs be transferred
between the Registered Entities and the Operators and Coordinators following the initial exchange of
information are changes made to the initial information. By requiring the Registered Entities to notify the
Operators and Coordinators shortly after changes are made the up to 15 month delay getting modifications to

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment
them is eliminated.

Yes

Ameren

This requirement is redundant with Standards FAC-008-1 and FAC-009-1. The existing standards already
cover ratings methodologies and reporting of facility ratings to the appropriate entities. In addition, these two
standards already require consideration of relaying equipment as one component in developing ratings
methodologies and in reporting of those ratings.

Yes

ERCOT ISO

It is not clear what the Planning Coordinator and Reliability Coordinator is supposed to do with this
information.

January 24, 2011

I don't believe this requirement is needed. Limiting a relay setting to 115% of the associated transmission
line’s highest seasonal 15 minute rating does not equate to a line that will trip before the operator has time to
intervene. It does not mean the line will trip in 15 minutes. In fact, the operator should be taking action well in
advance of reaching a 15 minute limit and the operator is likely only using the 15 minute rating in extreme
circumstances. Furthermore, PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1. FAC008-1 and FAC-009-1 already collectively require the Transmission Owner and Generator Owner to establish

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 3 Comment
a facilities ratings methodology, rate its facilities consistent with its methodology and to communicate those
ratings and methodology to its Planning Coordinator, Reliability Coordinator and Transmission Operator.
More specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner to consider relay
protective devices in its ratings methodology and FAC-009-1 R2 requires the communication of the ratings
including those limited by relays. As a result, neither PRC-023-2 R3 nor R4 is even needed. We assume the
drafting team must be aware of these FAC standard requirements because they did not even require
reporting to the Reliability Coordinator, Planning Coordinator and Transmission Operator of those circuits that
are actually limited by the relay per criterion 12. We agree that FAC-008-1 and FAC-009-1 collectively
establish the necessary requirements to compel the Transmission Owner and Generator Owner to
communicate these relay limited circuits and that no additional requirements are necessary.

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

4. Requirement R5 requires the Registered Entities that set transmission line relays according to Requirement R1 criterion 12 to provide a list of
the facilities associated with those relays to the Regional Entity at least once each calendar year, with no more than 15 months between
reports. Do you agree with Requirement R5? If not, please explain and provide specific suggestions for improvement.
Summary Consideration: In response to Question 4, stakeholders who responded to the question were fairly evenly divided
with about half indicating support for Requirement R5 and about half indicating disagreement with some aspect of the proposed
requirement.
The overwhelming concern submitted by the commenters was that while they didn’t necessarily have an issue with the
equipment owner communicating the relay limited circuits to the Regional Entities, they didn’t believe this information is needed
for reliability and, therefore, should not be included in the reliability standard. The drafting team pointed out in its response
that FERC Order 733 has directed that this requirement be explicitly addressed within the requirements of PRC-023-2.
The commenters were also concerned with the frequency requirements for providing this data to the Regional Entities. The
drafting team considered these concerns and revised the standard to require an updated list, and the associated measure was
modified to indicate that the updated list may either be a full list or a list of incremental changes to the previous list. The
drafting team believes that an annual update of the list is sufficient to satisfy the reliability goals of this requirement.
The drafting team also stated that including this requirement in the PRC-023 standard or collecting the data via a NERC Section
1600 Data Request are equally effective ways to address the directive. The drafting team has elected to address the directive
within the standard. The drafting team allows that if this requirement is moved to Section 1600 of the NERC Rules of
Procedure, it could be removed from the PRC-023 standard as part of the next subsequent revision.
The commenters also indicated that FERC Order 733 requires that the ERO document and have available upon request the list
of facilities that use this criterion. The proposed standard is not applicable to the Regional Entity so there is no method to
require the RE to provide the data to the ERO. The drafting team pointed out that each Regional Entity (RE), via the delegation
agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the information available to
respond to requests from users, owners, and operators of the BES.

Organization

Yes or No

Electric Market Policy

Yes

Potomac Holdings Inc & Affiliates

Yes

January 24, 2011

Question 4 Comment

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment
24 months after regulatory approvals.” However in the latest draft of the standard the 24 month requirement
was replaced with 6 months. Which is correct?

Yes

Pacific Northwest Small Public
Power Utility Comment Group

The FERC Order 733 page 224 states that this information is to be made available to the entities “by request.”
Unless a request happens to coincide with the annual submittal, this order is not being addressed. There is
also no requirement that the Regional Entity make the lists available to the other entities as ordered. We don’t
believe the intent of the order was achieved in R5.

Response: Thank you for your comment.
The requirement has been revised to require an updated list and the accompanying measure has been modified to indicate that the updated list may either be a
full list or a list of incremental changes to the previous list.
The drafting team believes that an annual update of the list is sufficient to satisfy the reliability goals of this requirement. The Regional Entity (RE), via the
delegation agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the information available to respond to requests from
users, owners, and operators of the BES.
Tri-State G & T System
Protection

Paragraph 224 of FERC Order no. 733 requires that the ERO document and have available upon request the
list of facilities that use this criterion. The proposed standard is not applicable to the Regional Entity so there
is no method to require the RE to provide the data to the ERO. That seems to indicate that the data should
be provided to the ERO rather than the Regional Entity. We also believe that an initial submittal is sufficient
until any responsible entity begins or stops using that criterion on any element. Periodic duplicate submittals
are unnecessary and unique submittals would more easily identify the loadability issues that the operators
need to consider. The FERC Order did not require annual submittals.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

delegation agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the information available to respond to requests from
users, owners, and operators of the BES.
Midwest ISO Standards
Collaborators

While we don’t necessarily have an issue with the equipment owner communicating these relay limited
circuits to the Regional Entities, we don’t believe this is needed for reliability and therefore it should not be
included in the reliability standard. Given that it is unclear what the information will even be used for, if it will
be needed long-term, and that it is likely will not change much, if at all, from year to year, we believe a data
request through NERC’s Rules of Procedure section 1600 would be more appropriate. In that way, we don’t
have to modify the standard later when NERC and the Regions determine they don’t need the data annually.

Response: Thank you for your comment.
The drafting team believes that including this requirement in the standard or collecting the data via Section 1600 are equally effective ways to address the
directive. The drafting team has elected to address the directive within the standard.
MRO's NERC Standards Review
Subcommittee

Yes

Bonneville Power Administration

Since a Registered Entity is already required to obtain the agreement of the Planning Coordinator,
Transmission Operator, and Reliability Coordinator and to use the calculated circuit capability as the Facility
Rating of the circuit as required by R3, BPA would like additional information regarding the purpose of
providing the Regional Entity a list each year. What would they do with the list?

Response: Thank you for your comment.
The requirement has been revised to require an updated list and the accompanying measure has been modified to indicate that the updated list may either be a

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

FE recognizes that the standard drafting team introduced Requirement R5 in response to a FERC directive
requiring NERC to document and make available upon request a list of protective relays set pursuant to
Requirement R1, Criterion 12. We commend FERC in their Order 733 decision to retain Criterion 12 over
accepting the preceding NOPR recommendation to remove it and support FERC’s desire in making
information readily available on entities application of Criterion 12 for its own use and other interested parties.
We are not opposed to providing our Regional Entity the information desired but believe this presents an
administrative task that can be accomplished outside of a mandatory and enforceable reliability requirement.
Since the reported data is for informational purposes and not a reliability need, we encourage the drafting
team propose to NERC staff an equally efficient and effective alternative of having the Regional Entity
periodically obtain the data through NERC’s Rules of Procedure, Section 1600 titled “Request for Data or
Information”.
Note: First Energy provided the following proposed changes to its comment:
“We are not opposed to providing our Regional Entity the information desired, however, FE believes it is more
efficient if the Registered Entity were to respond to a request for information from their Regional Entity. This
change would benefit both parties. The Regional Entity benefits by controlling when they receive the
information, rather than having to process data at different times throughout the year. The Registered Entity
benefits by limiting compliance exposure to an annual administrative task that could be easily overlooked.
Therefore, we propose that requirement R5 be revised as follows:

R5. Each Transmission Owner, Generator Owner, and Distribution Provider that sets transmission line relays
according to Requirement R1 criterion 12 shall provide a list of the facilities associated with those relays to its
Regional Entity upon request, within 30 days of the request. [Violation Risk Factor: Lower] [Time Horizon:
Long Term Planning]

Response: Thank you for your comment.
The requirement has been revised to require an updated list and the accompanying measure has been modified to indicate that the updated list may either be a

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

full list or a list of incremental changes to the previous list.
The drafting team believes that an annual update of the list is sufficient to satisfy the reliability goals of this requirement. The Regional Entity (RE), via the
delegation agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the information available to respond to requests from
users, owners, and operators of the BES.
The drafting team believes that including this requirement in the standard or collecting the data via Section 1600 are equally effective ways to address the
directive. The drafting team has elected to address the directive within the standard.
IRC Standards Review
Committee

Yes

New York Power Authority

Yes

Manitoba Hydro

Yes

Lakeland Electric

Yes

NIPSCO

We believe the R1 criterion 12 is needed- but the reporting requirement is not.

Response: Thank you for your comment.
Requirement R5 (reporting requirement to which you refer) has been revised to require an updated list and the accompanying measure has been modified to
indicate that the updated list may either be a full list or a list of incremental changes to the previous list.
The drafting team believes that an annual update of the list is sufficient to satisfy the reliability goals of this requirement. The Regional Entity (RE), via the
delegation agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the information available to respond to requests from

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

users, owners, and operators of the BES.
Western Area Power
Administration

Yes

Minnkota Power Cooperative,
Inc.

Yes

Duke Energy

Yes

Kansas City Power & Light

Yes

Orange and Rockland Utilities,
Inc.

Yes

City of Jacksonville Beach, FL
dba/Beaches Energy Services

January 24, 2011

No, once again, that is way too frequent and creates another unnecessary burden for record keeping. It
should be a much longer time criteria, say 5 years, with a requirement that if there is a CHANGE, the
information is sent to the PC, TO and RC.

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

Yes

Nebraska Public Power District

Yes

Great River Energy

Yes

Northeast Utilities

Yes

CenterPoint Energy

January 24, 2011

CenterPoint Energy disagrees with providing a list, as we cannot see any need and do not expect the
Regional Entity would have any use for this information. In discussions with Regional Entity personnel, they
were unsure of what use they would have for this information.

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

Yes

Oncor Electric Delivery Company
LLC

Oncor feels that the Requirement R5 is too cumbersome for the Registered Entities who have to, every 12 to
15 months, provide the Regional Entity a list of all the facilities that under Requirement R1 criterion 12 are
limited by the requirement to adequately protect the transmission line and cannot meet loadablity. It would
better for the Registered Entities to provide a one time list to its Regional Entity and then provide to the
Regional Entity any additions or deletions to the list no more than 30 days following any changes to the
relaying what would remove or add a transmission line to the list.

Yes

Ameren

Given that protective relaying equipment is already covered as one component in developing ratings in
standards FAC-008-1 and FAC-009-1, it is not clear that there is a reliability based need for the information
required to be provided in Requirement R5. Therefore, this requirement should be removed from the
proposed standard.

Response: Thank you for your comment.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 4 Comment

The requirement has been revised to require an updated list and the accompanying measure has been modified to indicate that the updated list may either be a
full list or a list of incremental changes to the previous list.
The drafting team believes that an annual update of the list is sufficient to satisfy the reliability goals of this requirement. The Regional Entity (RE), via the
delegation agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the information available to respond to requests from
users, owners, and operators of the BES.
FAC-008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the relay
loadability is based on established relay settings.
National Grid

Yes

ERCOT ISO

MidAmerican Energy

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

5. Requirement R6 requires each Planning Coordinator to apply the criteria in Attachment B to determine which transmission Elements must
comply with this standard. Do you agree with the requirement included in Requirement R6? If not, please explain and provide specific
suggestions for improvement.
Summary Consideration: In response to Question 5, stakeholders who responded to this question were fairly evenly divided
with about half indicating support for Requirement R6 and about half indicating disagreement with some aspect of the proposed
requirement.
The drafting team removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy with the Applicability section and
Attachment B. Within the Applicability section and Attachment B, a number of modifications were made based on industry
comments to improve clarity.
The drafting team replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No.
733, which references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of
circuits to be evaluated now refers to transmission lines and transformers operated below 100 kV “that are included on a critical
facilities list defined by the Regional Entity.”
The drafting team believes that to maintain consistency with the NERC Statement of Compliance Registry Criteria, should the
Regional Entity develop a critical facilities list for application of the Compliance Registry Criteria, the Planning Coordinator would
have to apply the criteria in Attachment B to determine for which of the circuits on the list the applicable entities must comply
with the standard.
While the drafting team acknowledges there is no requirement for the Regional Entity to provide the list, the drafting team
believes the Regional Entity will make a critical facilities list available as it is necessary for other entities to have this
information to support reliable operation of the interconnected transmission grid.
The drafting team understands the double jeopardy concern and has deleted Requirement R7 to resolve this concern.
The Effective Dates section of the standard was modified to address the timeline in which Facility owners must comply with
Requirements R1 through R5 when the Planning Coordinator identifies a circuit for which the Facility owner must comply with
the standard.

Organization

Yes or No

Electric Market Policy

Yes

Potomac Holdings Inc & Affiliates

Yes

January 24, 2011

Question 5 Comment

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Northeast Power Coordinating
Council

Yes

Pacific Northwest Small Public
Power Utility Comment Group

Yes

Tri-State G & T System
Protection

Yes

Midwest ISO Standards
Collaborators

Question 5 Comment

1) It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has
identified that are below 100 kV that are part of the Bulk Electric System. This information is not readily
available and there is no requirement for the Regional Entity to communicate it to them. Thus, inaction by
the auditor (i.e. Regional Entity) could actually cause the Planning Coordinator to violate this requirement.
This is clearly a conflict of interest.
2) Why does the Planning Coordinator need to identify which circuits are identified per criteria B4? There is
no justification given for this need and there is nothing else that appears to require action as a result of
this information. Thus, it is purely administrative and should be removed. Registered entities should
never be subject to potential sanctions for violations of purely administrative portions of requirements.
3) Why does the Planning Coordinator need to provide this information to the Reliability Coordinator? There
is nothing for the Reliability Coordinator to do with the information. The Reliability Coordinator only needs
to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1.

Response: Thank you for your comment.
1) If the Regional Entity develops a critical facilities list, the drafting team believes the Regional Entity will make this information available as it is necessary for
other entities to have this information to support reliable operation of the interconnected transmission grid.
2) The criteria in Attachment B provide a consistent methodology for Planning Coordinators to perform the determination presently assigned in Requirement R3
of PRC-023-1 (now Requirement R6 in PRC-023-2). This requirement supports the reliability purpose of this standard by identifying the circuits below 200 kV
which could lead to cascading outages, if Protection Systems are not set according to the relay loadability requirements. The action required as a result of this
determination is stated in Requirement R6: for circuits identified by the Planning Coordinator, the Transmission Owners, Generator Owners, and Distribution
Providers must comply with Requirements R1 through R5.
3) This portion of this requirement is included in PRC-023-1 and was not modified in PRC-023-2.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment

MRO's NERC Standards Review
Subcommittee

2) Why does the Planning Coordinator need to identify which circuits are identified per criteria B4? There is
no justification given for this need and there is nothing else that appears to require action as a result of
this information. Thus, it is purely administrative and should be removed. Registered entities should
never be subject to potential sanctions for violations of purely administrative portions of requirements.
3) Why does the Planning Coordinator need to provide this information to the Reliability Coordinator? There
is nothing for the Reliability Coordinator to do with the information. The Reliability Coordinator only needs
to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1.
Response: Thank you for your comment.
1) If the Regional Entity develops a critical facilities list, the drafting team believes the Regional Entity will make this information available as it is necessary for
other entities to have this information to support reliable operation of the interconnected transmission grid.
2) The criteria in Attachment B provide a consistent methodology for Planning Coordinators to perform the determination presently assigned in Requirement R3
of PRC-023-1 (now Requirement R6 in PRC-023-2). This requirement supports the reliability purpose of this standard by identifying the circuits below 200 kV
which could lead to cascading outages, if Protection Systems are not set according to the relay loadability requirements. The action required as a result of this
determination is stated in Requirement R6: for circuits identified by the Planning Coordinator, the Transmission Owners, Generator Owners, and Distribution
Providers must comply with Requirements R1 through R5.
3) This portion of this requirement is included in PRC-023-1 and was not modified in PRC-023-2.
Santee Cooper

Yes

FirstEnergy

Yes

While we agree with the intent of Requirement R6, FE believes improvements can be made to simplify and
clarify the R6 text.
a. Items 6.1 and 6.2 can be removed as they are duplicative with the two bulleted items listed at the forefront
of Attachment B.
b. Item 6.3 is awkwardly written based on the circular reference to R6. Its suggested that Item 6.3 be rewritten to say “Maintain a list of transmission Facilities operated below 200kV and deemed applicable to the

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment
PRC-023 standard per application of Attachment B”
c. Requirement R6 and Attachment B text seem to mix and interchange references to Glossary of Term
definitions “Elements” and “Facility”, although facility(ies) is often not capitalized, such that they are used
synonymously. As one example R6 indicates “...determine which transmission Elements must comply with
this standard ...” compared to Attachment B which says “... to determine the facilities which must comply with
this standard.” Sub items of R6 refer to keeping a list of “facilities” and not “Elements” as referenced in the
parent R6 requirement. For greater consistency we suggest the use of the term “Facility(ies)” over “Element”.
d. If the team believes a reference to a Planning Coordinator only needing to cover transmission facilities
within their footprint is needed, such as used in items 6.1 and 6.2 which are proposed for removal, the team
could revise the parent R6 text to read “ ... to determine which transmission Elements [Facilities] in its
Planning Coordinator area must comply with this standard.”
e. Replace the word “year” in item 6.5 with “planning study year”. It’s also recommended that the same
change occur in R7, to better clarify what “year” is referring to in R7.

Response: Thank you for your comment.
a) The standard text has been modified as you suggest.
b) The standard text has been modified as you suggest.
c) The drafting team has reviewed these terms for consistent usage throughout the standard. The drafting team now uses the NERC glossary term “Facility”
consistently throughout the document.
d) Although parts 6.1 and 6.2 have been removed as suggested, the drafting team has made changes in Requirement R6 that are consistent with the intent of
this comment.
e) The standard text has been modified as you suggest in Requirement R6. Requirement R7 has been deleted in response to other comments.
IRC Standards Review
Committee

1) Wording for R 6.2 is confusing. Revise to clearly state the intent of the requirement is for registered
entities to report to Regional Entities those facilities below 100KV that the requirements should apply to
and that the requirement for Regional Entities is only to make that list available.
2) It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has
identified that are below 100 kV that are part of the Bulk Electric System. This information is not readily
available and there is no requirement for the Regional Entity to communicate it to them. Thus, inaction by
the auditor (i.e. Regional Entity) could actually cause the Planning Coordinator to violate this requirement.
This is clearly a conflict of interest.
3) Why does the Planning Coordinator need to identify which circuits are identified per criteria B4? There is

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment
no justification given for this need and there is nothing else that appears to require action as a result of
this information. Thus, it is purely administrative and should be removed. Registered entities should
never be subject to potential sanctions for violations of purely administrative portions of requirements.
4) Why does the Planning Coordinator need to provide this information to the Reliability Coordinator? There
is nothing for the Reliability Coordinator to do with the information. The Reliability Coordinator only needs
to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1. Note: CAISO does not sign on to the above comments.

Response: Thank you for your comment.
1) The drafting team has eliminated parts 6.1 and 6.2 from Requirement R6. The drafting team understands that repeating this information in Requirement R6
and in Attachment B is redundant and potentially confusing. In addition, the drafting team has revised the text in Attachment B to more clearly convey the
intent.
2) If the Regional Entity develops a critical facilities list, the drafting team believes the Regional Entity will make this information available as it is necessary for
other entities to have this information to support reliable operation of the interconnected transmission grid.
3) The criteria in Attachment B provide a consistent methodology for Planning Coordinators to perform the determination presently assigned in Requirement R3
of PRC-023-1 (now Requirement R6 in PRC-023-2). This requirement supports the reliability purpose of this standard by identifying the circuits below 200 kV
which could lead to cascading outages, if Protection Systems are not set according to the relay loadability requirements. The action required as a result of
this determination is stated in Requirement R6: for circuits identified by the Planning Coordinator, the Transmission Owners, Generator Owners, and
Distribution Providers must comply with Requirements R1 through R5.
4) This portion of this requirement is included in PRC-023-1 and was not modified in PRC-023-2.
Tennessee Valley Authority

1) Per Requirement R6 criterion 2, the Planning Coordinator is better suited to analyze the subsystem and
its effect on the BES than the Regional Entity, so “Regional Entity” should be replaced with “Planning
Coordinator”.
2) Please also see Question 8 comment concerning the use of “flowgate” in Attachment B section B1.

Response: Thank you for your comments.
1) This criterion has been removed from the PRC-023-2 standard.
2) Please see our response to your comment in Question 8.
New York Power Authority

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment

1. We don’t think that the system would change that fast to warrant the additional work of conducting an
assessment every year. The entities involved have 24 months to make the necessary changes as given in
R7. If an annual assessment is required then this should be added as a requirement to TPL-001-2 rather than
buried in PRC-023. It would be more efficient to perform an assessment over the 10-year planning horizon
every 2-3 years. Critical facilities identified in the assessment can be monitored in the in-between years to
ensure construction schedules are on track and the need is still there. One initial detailed assessment of the
current year facilities could be done but then the assessment should be more focused on additions and
changes.

Manitoba Hydro

2. The VSLs for R6 are too severe. The system doesn’t change that rapidly and getting the list to the entities
involved before 60 days does not impact reliability given that they have 2 years to comply with changes.
Response: Thank you for your comments.
1. The drafting team intended that an assessment be performed each year, but that the power flow analyses used to support the assessment need not be
performed unless material changes to the system have occurred since the last assessment. The drafting team has added a footnote to criterion B4 to clarify
this intent.
The drafting team believes the one-to-five-year planning horizon is more appropriate for this requirement and has added this clarification in criterion B4. The
one-to-five-year planning horizon provides adequate lead-time for identifying circuits for which applicable entities must comply with PRC-023, while reducing
the level of uncertainty associated with the model compared to the 10-year planning horizon.
2. The VSL was approved as part of PRC-023-1 and has not been modified in PRC-023-2.
Lakeland Electric

In R6.2 the phrase “for the purposes of the Compliance Registry and” is used. The same phrase is also used
under Applicability in sections 4.2.3 and 4.2.6. What is the purpose of this phrase in these sections? I do not
think that the phrase has any value in these locations. The phrase is also used in the PRC-023 - Attachment
B in the second bullet under “Criteria”. It seems to imply that if a circuit is identified as a critical facility that
fact could be used to drive registration of an entity that otherwise may not require registration. If that is the
intent then I would suggest modifying the phrase in the attachment to “that may require entity registration in
the Compliance Registry “

Response: Thank you for your comment.
The phrase “for the purposes of the Compliance Registry” could include a circuit identified as a critical facility that could used to drive registration of an entity that
otherwise may not require registration. The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy with Applicability section and
Attachment B. Within the Applicability section and Attachment B, a number of modifications have been made based on industry comments to improve clarity. The
drafting team has replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which references text in section
III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of circuits to be evaluated now refers to transmission lines and

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment

transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.”
NIPSCO

Only the owner or TO GO DP should apply the criteria - which can be then reported to the PC

Response: Thank you for your comment.
The drafting team believes the Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform the
assessment in Attachment B. The drafting team also notes that assigning this responsibility solely to the Planning Coordinator is consistent with the approved
PRC-023-1 and FERC Order No. 733.
Western Area Power
Administration

Feel that NERC is delving too much into the technical details. Should allow Planning Coordinators to
establish their own study methodologies.

Response: Thank you for your comment.
The drafting team believes it is important that all Planning Coordinators utilize a consistent methodology for identifying the Facilities below 200 kV for which the
applicable entities must comply with PRC-023-2. FERC, in Order No. 733, identified concerns with lack of a consistent methodology and directed development of
a consistent methodology for inclusion in PRC-023.
Minnkota Power Cooperative,
Inc.

Many facilities with voltages between 100kV and 200kV will only impact a well-defined local load region if they
trip. There is no risk of cascading outages beyond the local load region. The criteria in Attachment B should
allow these types of facilities to be dismissed from evaluation.

Response: Thank you for your comment.
The criteria in Attachment B were selected to identify circuits that present a risk of cascading outages if relay loadability requirements are not met. The drafting
team has added to some of the criteria that the Planning Coordinator shall consult with the Facility owner when performing its assessment to provide the Facility
owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure so that a Facility owner
may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.
Duke Energy

1) R6.1 and R6.2 unnecessarily duplicate the first part of Attachment B, and should be deleted from R6.
2) R6.3 and R6.4 are both associated with maintaining the list and should be combined into a separate
requirement (new R7), with its own VRF and VSLs. Including the year for a facility should apply to all the
criteria, not just B4. Suggested wording for new R7: “Maintain a list of circuits that must comply with this
standard due to meeting Attachment B criteria. For each circuit, include the applicable criteria and the
year studied for which the criteria first applies, when a facility is added to the list.”

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment
3) R6.5 should become a new R8 with its own VRF and VSLs. No wording changes needed.

Response: Thank you for your comments.
1) The standard text has been modified as you suggest.
2) The drafting team believes that it is appropriate to include details regarding maintenance of the list as a part of Requirement R6 consistent with the existing
standard PRC-023-1. While the drafting team disagrees that parts 6.3 and 6.4 should become a separate requirement, the drafting team has combined these
into one part of Requirement R6 consistent with the commenters recommendation. The combined text, now part 6.1, reads:
“6.1

Maintain a list of circuits subject to PRC-023-2 per application of Attachment B, including identification of the first calendar year in which any
criterion in Attachment B applies.”

3) The structure of the standard text within R6 including the approved VRFs and VSLs is similar to R3 in PRC-023-1 and is therefore beyond the scope of the
project to modify.
Kansas City Power & Light

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment

Providers must comply with Requirements R1 through R5.
3) This portion of this requirement is included in PRC-023-1 and was not modified in PRC-023-2.
American Transmission
Company

Yes

Except ATC is recommending the following wording change for Requirement R 6.2 which provides
clarification on the application of the criteria: “Apply the criteria to the following Elements in its Planning
Coordinator Area, if any: those transmission lines operated below 100 kV and those transformers with low
voltage terminal connections below 100 kV that the Regional Entity has identified as critical facilities for the
purposes of the Compliance Registry.”

Yes

City of Jacksonville Beach, FL
dba/Beaches Energy Services

Yes

American Electric Power

The wording under Sections 4.2.3, 4.2.6, 6.2, and the applicability portion of Attachment B needs to be made
consistent to avoid any misinterpretations and confusion.- Section 4.2.3 - Delete the portion that reads “... and
the Planning Coordinator has determined are required to comply with this standard” for this section to read
the same as the associated sentence under the applicability portion of Attachment B.- Section 4.2.6 - Same
comment as Section 4.2.3 (above).- Section 6.2 - Reword to read: “Apply the criteria to transmission lines
operated below 100 kV and transformers with low voltage terminals connected below 100 kV that the
Regional Entity has identified as critical for the purposes of the Compliance Registry.”

Response: Thank you for your comment.
The drafting team agrees that inconsistency between these sections of the standard will lead to confusion. The drafting team has removed parts 6.1 and 6.2 from
Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B based on industry comments to provide consistency and clarity.
Nebraska Public Power District

January 24, 2011

Yes

If attachment B is kept then the PC should determine which transmission elements must comply with the
standard.

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment

Response: Thank you for your comment.
Great River Energy

1) It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity has
identified that are below 100 kV and that are part of the Bulk Electric System. This information is not
readily available and there is no requirement for the Regional Entity to communicate it to them. Thus,
inaction by the auditor (i.e. Regional Entity) could actually cause the Planning Coordinator to violate this
requirement. This is clearly a conflict of interest.
2) Why does the Planning Coordinator need to identify which circuits are identified per criteria B4? There is
no justification given for this need and there is nothing else that appears to require action as a result of
this information. Thus, it is purely administrative and should be removed. Registered entities should
never be subject to potential sanctions for violations of purely administrative portions of requirements.
3) Why does the Planning Coordinator need to provide this information to the Reliability Coordinator? There
is nothing for the Reliability Coordinator to do with the information. The Reliability Coordinator only needs
to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1

We agree that the PC should be held responsible for conducting the annual assessment, but we do not
understand the need for including “if the Regional Entity has identified either of these Element types as critical
facilities for the purposes of the Compliance Registry” in R6.2. We also do not understand the meaning of “as
critical facilities for the purpose of Compliance Registry”. There are established criteria for compliance
registry, but we are not aware of what constitutes “critical facilities for the purpose of compliance registry”.
For the purpose of determining compliance with the relay loadability requirements, having the PC to make
such an assessment and determination would suffice. If the intent is to limit the facilities to be assessed to

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment
only those that have been identified as “critical facilities for the purpose of compliance registry”, then it implies
that those that are not identified are not required to be assessed. This may in fact result in missing some
facilities that may be critical from a relay loadability standpoint.
Further, the term “critical facilities” is used very loosely in different standards, and can mean very different
things for various applications and under various circumstances. We suggest to remove ““if the Regional
Entity has identified either of these Element types as critical facilities for the purposes of the Compliance
Registry” from the requirement.
For the same reason, we suggest the quoted phrase be removed from the Applicability Section, any other
requirements in this standard, and Attachment B.

Response: Thank you for your comment.
The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy with Attachment B. Within Attachment B, a number of modifications
have been made based on industry comments to improve clarity. The drafting team has replaced the phrase “critical for the purposes of the Compliance Registry”
with text from ¶60 of Order No. 733, which references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of
circuits to be evaluated now refers to transmission lines and transformers operated below 100 kV “that are included on a critical facilities list defined by the
Regional Entity. It is the intent of the drafting team, consistent with the directive in Order No. 733, to only require assessment of circuits operated below 100 kV if
they have been identified by the Regional Entity as noted. The drafting team believes circuits that could lead to cascade tripping if relay loadability requirements
are not met would be included on a critical facilities list defined by the Regional Entity.
Northeast Utilities

Yes

CenterPoint Energy

(a) CenterPoint Energy recommends revising R6 to require Planning Coordinators to coordinate with
associated Transmission Planners in the determination of which 100 - 200 kV elements must comply with this
standard.
(b) CenterPoint Energy recommends criterion B5 be deleted, as it is too broad and gives the Planning
Coordinator too much discretion in determining other facilities which must comply with this Standard. In the
case that criteria B5 is not deleted, CenterPoint Energy recommends that a process be required where
Transmission Planners can appeal the inclusion of specific Transmission elements that must comply with this
standard.
(c) CenterPoint Energy recommends eliminating the un-capitalized term “critical” to remove any confusion
with NERC CIP reliability standards. The voluntary NERC relay loadability review in 2006 used the term
“operationally significant element” for elements 100 - 200 kV. CenterPoint Energy recommends using
“operationally significant” wherever “critical” is used within PRC-023-2.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment

Response: Thank you for your comment.
(a) The drafting team believes the Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform
the assessment in Attachment B. The drafting team also notes that assigning this responsibility solely to the Planning Coordinator is consistent with the
approved PRC-023-1 and FERC Order No. 733.
(b) The drafting team has modified criterion B5 in response to industry comments to require that if the Planning Coordinator selects a circuit based on technical
studies or assessments, other than those specified in criteria B1 through B4, that such selection is to be made in consultation with the Facility owner to provide
the Facility owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure so that a
Facility owner may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.
(c) The context in which the term “critical” is used is different than in the NERC “Zone 3” and “Beyond Zone 3” reviews. The remaining references to the term
critical are in the context of NERC Statement of Compliance Registry Criteria. Rather than using the term “operationally significant,” the drafting team has
replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which references text in section III.d.2 of the
NERC Statement of Compliance Registry Criteria. So the second category of circuits to be evaluated now refers to transmission lines and transformers
operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team made corresponding modifications to the
Applicability section.
New York Independent System
Operator

Wording for R6.2 is confusing. It is not clear how the Planning Coordinator is supposed to know which
facilities the Regional Entity has identified that are below 100 kV. This information is not readily available and
there is no requirement for the Regional Entity to communicate it to them. Revise to clearly state the intent of
the requirement is for registered entities to report to Regional Entities those applicable facilities below 100kV
and that the requirement for Regional Entities is only to make that list available. There is no justification given
in R6.4 for the need to identify facilities for which criterion B4 applies and there is no further required action as
a result of this information. Thus, it is purely administrative and should be removed. Registered entities
should never be subject to potential sanctions for violations of purely administrative portions of requirements.

Response: Thank you for your comment.
The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy with Attachment B. Within Attachment B, a number of modifications
have been made based on industry comments to improve clarity. The drafting team has replaced the phrase “critical for the purposes of the Compliance Registry”
with text from ¶60 of Order No. 733, which references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of
circuits to be evaluated now refers to transmission lines and transformers operated below 100 kV “that are included on a critical facilities list defined by the
Regional Entity.” The drafting team believes the Regional Entity will make this information available as it is necessary for other entities to have this information to
support reliable operation of the interconnected transmission grid.
Oncor Electric Delivery Company
LLC

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Consolidated Edison Co. of NY,
Inc.

Yes

Ameren

Question 5 Comment

Section 6.2 is unclear and seems arbitrary in the statement ‘if the Regional Entity has indentified either of
these Element types as critical facilities for the purpose of the Compliance registry’. A clear test is lacking.

Response: Thank you for your comment.
The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B (which
used the same phrase) based on industry comments to provide clarity. The drafting team has replaced the phrase “critical for the purposes of the Compliance
Registry” with text from ¶60 of Order No. 733, which references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second
category of circuits to be evaluated now refers to transmission lines and transformers operated below 100 kV “that are included on a critical facilities list defined by
the Regional Entity.” The test by which the Regional Entity may make this determination is outside the scope of this standard.
National Grid

Yes

ERCOT ISO

ERCOT ISO is unclear, as to what is meant by the reference to the Compliance Registry. Additionally,
ERCOT ISO feels the Regional Entities are not the appropriate entities to declare which elements (below
100kV) should be considered critical. For 6.2 and Attachment B, ERCOT ISO suggests completely removing
the existing language pertaining to facilities operated below 100kV.

Response: Thank you for your comment.
The drafting team believes it would be inappropriate to remove all language pertaining to facilities operated below 100 kV, as Order No. 733 directs consideration
of such facilities and the NERC Statement of Compliance Registry Criteria permits applicability of NERC Reliability Standards to certain facilities operated below
100 kV. The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B
based on industry comments to provide clarity. The drafting team has replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60
of Order No. 733, which references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of circuits to be
evaluated now refers to transmission lines and transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.”
MidAmerican Energy

January 24, 2011

1) Sections 4.2.2, 4.2.3, 4.2.6, R6, and Attachment B needs to be modified with a superior alternative than
the FERC recommendation to assign the PC the responsibility to determine a sub-200 kV critical facility
test. NERC needs to re-assign this to the Transmission Owners and Operators as the entities that
properly perform transmission planning analysis. The PC's aren't the proper entities that understand and
perform the proper analyses. Therefore the superior alternative is to re-assign the responsibility to the
party that understand what is truly critical and why. At a minimum Transmission Owners and / or
Operators should be added to ensure that the entities that best understand the operation of the electric

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 5 Comment
grid. It is not clear how the Planning Coordinator is supposed to know which facilities the Regional Entity
has identified that are below 100 kV that are part of the Bulk Electric System. This information is not
readily available and there is no requirement for the Regional Entity to communicate it to them. Thus,
inaction by the auditor (i.e. Regional Entity) could actually cause the Planning Coordinator to violate this
requirement. This is clearly a conflict of interest.
2) Why does the Planning Coordinator need to identify which circuits are identified per criteria B4? There is
no justification given for this need and there is nothing else that appears to require action as a result of
this information. Thus, it is purely administrative and should be removed. Registered entities should
never be subject to potential sanctions for violations of purely administrative portions of requirements.
3) Why does the Planning Coordinator need to provide this information to the Reliability Coordinator? There
is nothing for the Reliability Coordinator to do with the information. The Reliability Coordinator only needs
to be informed if equipment becomes derated and then that should occur through the normal
communication of ratings per FAC-009-1.

Response: Thank you for your comment.
1) The drafting team believes the Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform
the assessment in Attachment B. The responsibilities defined in the NERC Function Model for the Transmission Operator and Transmission Owner are not
consistent with skills necessary to perform these assessments. The drafting team also notes that assigning this responsibility solely to the Planning
Coordinator is consistent with the approved PRC-023-1 and FERC Order No. 733.
The drafting team has replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which references text in
section III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of circuits to be evaluated now refers to transmission lines and
transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team believes the Regional Entity
will make this information available as it is necessary for other entities to have this information to support reliable operation of the interconnected transmission
grid.
2) The criteria in Attachment B provide a consistent methodology for Planning Coordinators to perform the determination presently assigned in Requirement R3
of PRC-023-1 (now Requirement R6 in PRC-023-2). This requirement supports the reliability purpose of this standard by identifying the circuits below 200 kV
which could lead to cascading outages, if Protection Systems are not set according to the relay loadability requirements. The action required as a result of this
determination is stated in Requirement R6: for circuits identified by the Planning Coordinator, the Transmission Owners, Generator Owners, and Distribution
Providers must comply with Requirements R1 through R5.
3) This portion of this requirement is included in PRC-023-1 and was not modified in PRC-023-2.
Xcel Energy

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

6. Requirement R7 requires the Registered Entities to implement Requirement R1, Requirement R2, Requirement R3, Requirement R4, and
Requirement R5 for each facility that the Planning Coordinator added to the list of facilities that must comply with this standard (per
Requirement R6) by certain dates following notification by the Planning Coordinator. Do you agree with Requirement R7? If not, please
explain and provide specific suggestions for improvement.

Summary Consideration: In response to Question 6, most stakeholders indicated support for Requirement R7, but there
were some strong objections.
Two significant items were addressed and resolved by the drafting team in response to comments received from the industry.
First, the drafting team understands the double jeopardy concern between R1 through R5 and Requirement R7 and therefore
deleted Requirement R7. The Effective Dates section has been modified to address the timeframe in which Facility owners must
comply with Requirements R1 through R5 when the Planning Coordinator identifies a circuit for which the Facility owner must
comply with the standard.
Secondly, the drafting team has considered a number of comments regarding the implementation timeframe for the standard
requirements and has extended the implementation time frame to 39 months to provide the Facility owners time to budget,
procure, and install any protection system equipment modifications and for consistency with PRC-023-1.

Organization

Yes or No

Electric Market Policy

Yes

Potomac Holdings Inc & Affiliates

Yes

Northeast Power Coordinating
Council

Yes

Pacific Northwest Small Public
Power Utility Comment Group

Yes

Tri-State G & T System
Protection

Yes

Midwest ISO Standards
Collaborators

January 24, 2011

Question 6 Comment

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 6 Comment
because failure to comply with Requirements 1-5 would represent a violation of Requirement 7 also.

Response: Thank you for your comment.
The drafting team understands the double jeopardy concern and has deleted Requirement R7. The Effective Dates section has been modified to address the
timeframe in which Facility owners must comply with Requirements R1 through R5 when the Planning Coordinator identifies a circuit for which the Facility owner
must comply with the standard.
MRO's NERC Standards Review
Subcommittee

We do not believe that R7 is needed. The applicability section of the standard is clear that the standard
applies to those circuits identified in R6. This requirement could be construed as potential for double jeopardy
because failure to comply with Requirements 1 through 5 would represent a violation of both Requirement 7
and Requirements 1 through 5.

Yes

Bonneville Power Administration

BPA feels the applicable date descriptions are too confusing and would like to see more clarity and
simplification.

Response: Thank you for your comment.
The referenced date descriptions are consistent with the phraseology used in existing approved NERC standards.
FirstEnergy

Yes

We support the minimum 24 month implementation timeframe because a responsible entity will need
sufficient time to allow for any capital expenditures that may be required due to additional facilities identified
by the Planning Coordinator.

Response: Thank you for your comment.
The drafting team notes that in response to other comments, and for consistency with PRC-023-1, the implementation time frame has been extended to 39
months.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 6 Comment

We do not believe that R7 is needed. The applicability section of the standard is clear that the standard
applies to those circuits identified in R6. This requirement could be construed as potential for double jeopardy
because failure to comply with Requirements 1-5 for represent a violation of both Requirement 7 and
Requirement 1-5.

IRC Standards Review
Committee

Response: Thank you for your comment.
The drafting team understands the double jeopardy concern and has deleted Requirement R7. The Effective Dates section has been modified to address the
timeline in which Facility owners must comply with Requirements R1 through R5 when the Planning Coordinator identifies a circuit for which the Facility owner
must comply with the standard.
Tennessee Valley Authority

Yes

New York Power Authority

Yes

Manitoba Hydro

The effective date should not be a uniform date, it should be dependent on the number of circuits that have
been identified and determined as critical circuits for an individual utility.

Response: Thank you for your comment.
The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation time frame to 39 months
to provide the Facility owners time to budget, procure, and install any protection system equipment modifications and for consistency with PRC-023-1.
Lakeland Electric

Yes

NIPSCO

We believe only the owners of facilities should have this requirement, not the PC

Response: Thank you for your comment.
The drafting team believes that the standard requirement only applies to the owners of the facilities. However, the drafting team notes that Requirement R7 has
been deleted in response to other comments.
Western Area Power
Administration

Yes

Minnkota Power Cooperative,

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 6 Comment

Inc.
Duke Energy

Since the Attachment B criteria are applied beyond the operating horizon, R7 should be rewritten (and also
renumbered as R9). Suggested wording: “ Each Transmission Owner, Generator Owner, and Distribution
Provider shall implement Requirement R1, Requirement R2, Requirement R3, Requirement R4, and
Requirement R5 for each facility that is added to the Planning Coordinator’s list of facilities that must comply
with this standard pursuant to Requirement R6, by the first day of the first calendar quarter of the year in
which Attachment B criteria first apply. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

Response: Thank you for your comment.
The drafting team notes that Requirement R7 has been deleted in response to other comments. The Effective Dates section has been modified to address the
timeframe in which Facility owners must comply with Requirements R1 through R5 when the Planning Coordinator identifies a circuit for which the Facility owner
must comply with the standard.
Kansas City Power & Light

We do not believe that R7 is needed. The applicability section of the standard is clear that the standard
applies to those circuits identified in R6. This requirement could be construed as potential for double jeopardy
because failure to comply with Requirements 1-5 for represent a violation of both Requirement 7 and
Requirement 1-5.

ATC believes it is difficult to determine without knowing the full scope of work. Until the Planning criteria can
be determined, the scope is unknown. Assuming not many assets are added, two years would be a more
reasonable amount of time.

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

City of Jacksonville Beach, FL
dba/Beaches Energy Services

Yes

American Electric Power

Question 6 Comment

Need to provide a 60-month timeline to implement the noted requirements for each facility that is added to the
Planning Coordinator’s initial list of facilities that must comply with this standard, versus the 24-month timeline
to implement the noted requirements for each facility that is added to the Planning Coordinator’s established
list of facilities that must comply with this standard. This is a practical consideration that recognizes the high
likelihood that the number of facilities that will be identified during development of the initial list of facilities will
be many times greater than the incremental number of facilities that will be identified during the annual
assessments and added to the established list of facilities. In addition, need to specify under this requirement
whether any facilities that drop off the Planning Coordinator’s list of facilities while still within the applicable
(60-month or 24-month) implementation timeline must still comply with this standard.

Yes

Great River Energy

Yes

Northeast Utilities

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 6 Comment

CenterPoint Energy believes Requirement 7 should be deleted from PRC-23-2, as it an Effective Date /
Implementation Plan issue. Instead the wording should be included in PRC-023-2 in Effective Dates item 5.5
and within the Implementation Plan.

CenterPoint Energy

R7 is unnecessary as the applicability section of the standard is clear that the standard applies to those
circuits identified in R6. This requirement could be construed as potential for double jeopardy because failure
to comply with Requirements 1-5 represents a violation of both Requirement 7 and Requirements 1-5.

Yes

Consolidated Edison Co. of NY,
Inc.

Yes

Ameren

As this requirement is structured, it creates a potential for double jeopardy should one of the other
requirements mentioned (R1 through R5) be violated. This requirement is not needed and should be
removed from the proposed standard.

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

ERCOT ISO

Yes

MidAmerican Energy

Question 6 Comment

We do not believe that R7 is needed. The applicability section of the standard is clear that the standard
applies to those circuits identified in R6. This requirement could be construed as potential for double jeopardy
because failure to comply with Requirements 1-5 for represent a violation of both Requirement 7 and
Requirement 1-5.

January 24, 2011

Yes

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

7. PRC-023 - Attachment A, section 1.6 has been revised to avoid unintended negative impact on reliability associated with referring to
“Protective functions that supervise operation of other protective functions.” Section 1.6 has been revised to “Supervisory elements associated
with current-based, communication-assisted schemes where the scheme is capable of tripping for loss of communications” to be more specific
to the concern stated in Order No. 733. Do you agree that this is an equally efficient and effective method of meeting this directive? If not,
please explain and provide specific suggestions for improvement.

Summary Consideration: In response to Question 7, most stakeholders who responded to the question indicated support for
Section 1.6.
Several commenters questioned the applicability of this requirement only to current-based telecommunication schemes to
which the drafting team responded “Current-differential telecommunications systems are different than other
telecommunications systems, in that the sensitivities for the protection elements are often set very sensitively – well below load
current – and depend on the integrity of the channel to make a trip/no trip decision where other telecommunication system
technologies require the operation of other protection system elements (usually distance elements) which are already subject to
the requirements of this standard. Therefore, they will trip immediately due to load current upon the loss of communications,
and are dependent on the fault detectors to inhibit trip which must therefore be secure regardless of how infrequently loss of
communications may occur”.
There are also comments addressing supervisory elements vs. loss of potential to which the drafting team responded “For a
loss-of-potential, there will often be indications that the condition exists, allowing rapid response for repair.”

Organization

Yes or No

Electric Market Policy

Yes

Potomac Holdings Inc & Affiliates

Question 7 Comment

The current wording of section 1.6 is a significant improvement over the previous version. The intent of
this section was to specifically address phase overcurrent supervising elements (i.e. phase fault
detectors) associated with pilot wire, phase comparison, and line current differential schemes where the
scheme is capable of tripping for loss of communications. However, we believe that the term “currentbased communication-assisted schemes” is too generic and may be confusing without mention of the
specific schemes to which this requirement applies.
Also, only phase overcurrent supervising elements are in scope, not ground overcurrent supervising
elements. Therefore, to clarify the requirement we suggest replacing the current wording with either
“Phase overcurrent supervisory elements (i.e. phase fault detectors) associated with pilot wire, phase

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 7 Comment
comparison, and line current differential schemes, where the scheme is capable of tripping for loss of
communications” or “Phase overcurrent supervisory elements (i.e. phase fault detectors) associated with
current-based communication-assisted schemes (i.e. pilot wire, phase comparison, and line current
differential) where the scheme is capable of tripping for loss of communications”.

Response: Thank you for your comment.
Attachment A applies to the listed protective functions that respond to load so it’s unnecessary to use the word “phase”. Section 1.6 has otherwise been modified
essentially as you suggest in response to your comment.
Northeast Power Coordinating
Council

Yes

Pacific Northwest Small Public
Power Utility Comment Group

Yes

Tri-State G & T System
Protection

Yes

Midwest ISO Standards
Collaborators

Yes

MRO's NERC Standards Review
Subcommittee

Yes

Santee Cooper

Yes

Bonneville Power Administration

Yes

FirstEnergy

Yes

IRC Standards Review
Committee

Yes

Tennessee Valley Authority

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

New York Power Authority

Yes

Manitoba Hydro

Question 7 Comment

Effectively, there is no substantial difference between the protection elements described in section 1.6 and
the protection elements described on second bullet in Section 2.1. Why should the protection elements in
section 1.6 be included?
During loss of communication, the supervisory elements associated with current based, communicationassisted schemes (such as line current differential scheme and phase comparison scheme) may be the only
protection elements to provide high speed protection which may be necessary from system reliability
perspective. As a result, these supervisory elements should be set low enough to ensure that they can
detect all fault condition. Since these supervisory elements are only in effect under loss of communication
contingency, I don’t think they should be subjected to the same requirements as those load responsive
elements under normal condition. They should be treated the same as those elements described on the first
bullet in section 2.1.

Response: Thank you for your comment.
Current-differential telecommunications systems are different than other telecommunications systems, in that the sensitivities for the protection elements are
often set very sensitively – well below load current – and depend on the integrity of the channel to make a trip/no trip decision where other telecommunication
system technologies require the operation of other protection system elements (usually distance elements) which are already subject to the requirements of
this standard. Therefore, they will trip immediately due to load current upon the loss of communications, and are dependent on the fault detectors to inhibit trip
which must therefore be secure regardless of how infrequently loss of communications may occur. For a loss-of-potential, there will often be indications that
the condition exists, allowing rapid response for repair.
Lakeland Electric

Yes

NIPSCO

Don’t know what is referred to here except maybe a current differential scheme. There is no need for this
added requirement.

Response: Thank you for your comment.
Current-differential telecommunications systems are different than other telecommunications systems, in that the sensitivities for the protection elements are often
set very sensitively – well below load current – and depend on the integrity of the channel to make a trip/no trip decision where other telecommunication system
technologies require the operation of other protection system elements (usually distance elements) which are already subject to the requirements of this standard.
Therefore, they will trip immediately due to load current upon the loss of communications, and are dependent on the fault detectors to inhibit trip which must
therefore be secure regardless of how infrequently loss of communications may occur.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Western Area Power
Administration

Question 7 Comment
Both the FERC order and section 1.6 are unclear.

Response: Thank you for your comment.
Absent the specific comment, the drafting team is unable to respond. In response to other comments, the drafting team has modified Section 1.6 to provide
additional clarity.
Minnkota Power Cooperative,
Inc.

Yes

Duke Energy

Yes

Kansas City Power & Light

Yes

American Transmission
Company

Yes

Orange and Rockland Utilities,
Inc.

Yes

City of Jacksonville Beach, FL
dba/Beaches Energy Services

Yes

American Electric Power

The wording of Attachment A, section 1.6 needs to be made consistent to avoid any confusion.1.6 Reword to
read: "Supervisory elements used as fault detectors associated with pilot wire or current differential protection
systems where the system is capable of tripping for loss of communications".

Response: Thank you for your comment.
Section 1.6 has been modified essentially as is suggested in the comment.
Nebraska Public Power District

Yes

Great River Energy

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Northeast Utilities

Yes

New York Independent System
Operator

Yes

Oncor Electric Delivery Company
LLC

Yes

Consolidated Edison Co. of NY,
Inc.

Yes

Ameren

Question 7 Comment

Section 1.6 is contrary to section 2.0 and seems arbitrary. Why is a communication system for a currentbased scheme treated to a higher standard than other communications scheme? The communications
scheme reliability is covered through the maintenance and misoperations analysis standards.

Response: Thank you for your comment.
Current-differential telecommunications systems are different than other telecommunications systems, in that the sensitivities for the protection elements are often
set very sensitively – well below load current – and depend on the integrity of the channel to make a trip/no trip decision where other telecommunication system
technologies require the operation of other protection system elements (usually distance elements) which are already subject to the requirements of this standard.
Therefore, they will trip immediately due to load current upon the loss of communications, and are dependent on the fault detectors to inhibit trip.
National Grid

Yes

ERCOT ISO

Yes

MidAmerican Energy

Yes

Xcel Energy

Yes

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

8. Attachment B contains the test that the Planning Coordinators must use to determine which transmission elements (transmission lines
operated below 200 kV and transformers with low voltage terminals connected below 200 kV) must comply with this standard. Do you agree
that the method proposed in Attachment B is a technically sound approach? If not, please explain and provide specific suggestions for
improvement.

Summary Consideration: In response to Question 8, most stakeholders who responded to this question indicated
disagreement with the method proposed in Attachment B.
The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system
adjustment in between contingencies in Attachment B, criterion B4. The purpose of this criterion is not to assess whether the
system performance meets the TPL standard; rather, it is to be used as a screen to determine whether relays must be set to
meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the initiating
outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that
the loadings respect the published applicable ratings of the circuits. It does require that engineering judgment be used to
select certain combinations of line outages to be studied without manual system adjustment to ensure that, if the manual
adjustments were not completed before the second contingency, the relay settings on the lines remaining in service would not
inappropriately trip the lines.
The drafting team has modified criterion B5 in response to industry comments to require that if the Planning Coordinator selects
a circuit based on technical studies or assessments, other than those specified in criteria B1 through B4, that such selection
shall be made in consultation with the Facility owner to provide the Facility owner an opportunity for input into the assessment.
Additionally, an appeals process will be included in the NERC Rules of Procedure so that a Facility owner may appeal a decision
in the event it believes a circuit is incorrectly identified by the Planning Coordinator.
Commenters expressed concern that the proposed implementation plan for PRC-023-2 has the unintended consequence of
shortening the time provided for Facility owners to comply with Requirement R1 for switch-on-to-fault schemes. The drafting
team has modified the effective dates in the standard to address this problem
Commenters indicated clarification was needed to identify which Interconnection Reliability Operating Limits (IROLs) are to be
considered in application of Attachment B, criterion B2. Also, there was some confusion as to the requirements of the standard,
since the long term planning horizon may include transmission projects that have not been built or alternative system
configurations that do not exist, making it impossible for affected parties to set their relays appropriately. In response to
several comments on this subject, the drafting team has replaced the reference to “determined in the long-term planning
horizon” with “determined in the planning horizon pursuant to FAC-010.”
In response to comments on criterion B3, the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant
Interface Requirements (NPIRs) pursuant to NUC-001.” The drafting team believes this modification to criterion B3 provides a
level of measurability that should address the commenters’ concerns.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Many commenters expressed their belief that flowgates are market-based tools that are not appropriate for use in assessing
system reliability. The drafting team responded that congestion and system reliability are not mutually exclusive concerns.
Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated,
could lead to instability, uncontrolled separation, or cascading. While flowgates are used to manage congestion, the underlying
basis for doing so is to preserve system reliability. As such, it is appropriate and necessary to include monitored Facilities of
flowgates as applicable circuits under PRC-023-2.
Based on a number of comments, the drafting team has modified Attachment B, criterion B1 to refer to “permanent” flowgates
and has replaced the reference to “long-term reliability concerns” with “reliability concerns for loading of that circuit.” The
drafting team believes this more clearly reflects the intent to exclude flowgates that are established on a temporary basis and
more clearly identifies the role of the Planning Coordinator in applying criterion B1.

Organization

Yes or No

Electric Market Policy

Question 8 Comment
5.1 Requirement R1. Dominion would like to see the exception of "switch on to fault" schemes added back in.

Response: Thank you for your comment.
The drafting team understands the commenter’s concern that the proposed implementation plan for PRC-023-2 had the unintended consequence of shortening
the time provided for Facility owners to comply with Requirement R1 for switch-on-to-fault schemes. The drafting team has modified the effective dates in the
standard to address this problem.
Potomac Holdings Inc & Affiliates

Yes

Northeast Power Coordinating
Council

1) B2. Item B2 adds significant confusion to the process. The long term planning horizon may include
transmission projects which have not even been built or alternative system configurations which do not
exist, making it impossible for affected parties to set their relays appropriately. Suggested replacement
language to avoid this issue: “Each circuit that is a monitored element of an IROL, assuming that all
transmission elements are in service and the system is under normal conditions.”
2) B3. This item indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement
by the plant and the Transmission Entity it should be removed from Attachment B and placed elsewhere
in the document. If this is intended to apply to the Planning Coordinator, Transmission Entity should be
replaced with Planning Coordinator. Why does B3 only apply to Nuclear Power Plants?
3) B4. This criterion is overly stringent and should be deleted. The system is neither planned nor operated
to allow for two overlapping outages without operator action in between. If this criterion is retained, it

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
should be made consistent with the requirements of TPL-003 where operator actions can be assumed
between the first and second contingencies. Since a similar comment was made previously, more
information is being provided following.1. Since the system is neither planned nor operated to two
overlapping outages in between, such testing may result in unsolved cases, or voltages well below
criteria. In the case of an unsolved case, there are no flows to evaluate, making this standard impossible
to apply. In the case of a solved case with voltages well below criteria, currents are likely to be incredibly
high and therefore viewed as unrealistic. These concerns may limit the contingency selection to those
which are not severe, eliminating any perceived benefit from this testing.2. There is no guidance provided
on how the system should be dispatched in the model upon which the overlapping contingencies are
tested. This will result in significant discrepancies between the base assumptions used by the various
Planning Coordinators. The contents of this standard should be reviewed to reflect the new definition of
the Bulk Electric System.

Response: Thank you for your comment.
1) In response to several comments on this subject the drafting team has replaced the reference to “determined in the long-term planning horizon” with
“determined in the planning horizon pursuant to FAC-010.”
2) T his criterion applies to the Planning Coordinator and requires that the Planning Coordinator include circuits that form a path “(as agreed to by the plant
owner and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs) pursuant to
NUC-001” on the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes the
added reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
3) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
Pacific Northwest Small Public
Power Utility Comment Group

We thank the SDT for addressing our concern regarding radially operated circuits. We note, however, that the
key word “operated” from the consideration of comments was dropped before it reached the standard. Please
change the last bullet of B4 to:"Radially operated circuits serving only load are excluded."

Response: Thank you for your comment.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

The drafting team agrees with your comment and has modified criterion B4 accordingly.
Tri-State G & T System
Protection

Yes

1) While we agree that it is a technically sound approach, we have concerns that the criterion B4 is overburdensome. Paragraph 82 of FERC Order 733 indicates that the existing TPL simulations and
assessments should be a component of the test. By excluding manual intervention in the assessments
the Attachment is expanding the scope beyond the Commission’s Order. We think there should be a test
based on the existing assessments required by the TPL standards that would then trigger a subsequent
test with no manual intervention. An example would be if an element’s loading exceeded 100% of its
Facility Rating using the normal assessment, then the assessment with no manual intervention would be
applied and subsequent steps of criterion B4 would be followed.
2) We think that criterion B5 is too vague, may be discriminatory, is unnecessary, and should be removed.
There is very little basis listed for this criterion above and beyond those listed in criterion B4, the criterion
may be applied discriminatorily or differently even within the same interconnection, it potentially excludes
the protection system owner from having input in the process, and there is no redress for appeal by the
owner. It seems highly unlikely that elements that are not identified through criterion B4 will need to be
included. If some form of criterion B5 is included in Attachment B, then it needs to better define a
technical basis for the request for inclusion, a procedure to initiate the request for inclusion, due process
defined for evaluation of the request, and inclusion of the protection system owner in the evaluation
process and the agreement.

Response: Thank you for your comment.
1) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
2) The drafting team has modified criterion B5 in response to industry comments to require that if the Planning Coordinator selects a circuit based on technical
studies or assessments, other than those specified in criteria B1 through B4, that such selection is to be made in consultation with the Facility owner to provide
the Facility owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure so that a
Facility owner may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.
Midwest ISO Standards
Collaborators

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
flowgate includes two components. Let’s focus on the first component which represents those flowgates
defined in the IDC. Because IDC flowgates list is updated monthly and the IDC users can add temporary
flowgates to the IDC at any time, this is an inappropriate list to use. We appreciate the drafting team’s
attempt to resolve this issue by including the caveat “that has been included to address long-term
reliability concerns, as confirmed by the applicable Planning Coordinator.” However, this really only
confuses the matter and does not solve it. Reliability Coordinators add flowgates to manage real-time
congestion. Planning Coordinators do not. Per the NERC functional model, they do not even have a role
in deciding which flowgates to add to the IDC. Flowgates are added to the IDC to mitigate existing,
known congestion points not congestion points identified in a long-term planning study that may never
materialize due to changing conditions. Thus, IDC flowgates should be specifically excluded.Now let us
focus on the second component of flowgate. The second component is much like the first component in
that is it a mathematical construct to analyze the impact of power flows on the BES except is not required
to be included in the IDC. There is nothing in the definition of a flowgate to give credence that is
represents anything more than point to calculate power flows and the impact of transactions. Flowgates
are primarily used to manage congestion on the system and to sell transmission system. Because it is
convenient to select a group of lines as a proxy to sell transmission service or manage congestion does
not mean that those group of lines represent a reliability issue. Thus, we do not believe any flowgates
should be included in the list. Any true reliability issues can be identified through the TPL studies and
those facilities that do not meet the performance requirements are what should be used.
2) We do not support criterion B4. It exceeds what is required in the TPL standards and what is required per
the reliability directive in Order 729. The TPL standards allow system operator intervention for category
C3 contingencies between the two independent Category B contingencies. This standard should not
exceed those requirements in the TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the
relevant directives regarding the Planning Coordinator test. Paragraph 79 states that the test “must
include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in
transmission planning.” Paragraph 80 states that “the test must be consistent with the general reliability
principles embedded in the existing series of TPL” standards. Thus, exceeding the TPL standards could
be argued as deviating from the directive. In response to comments that did not support this criterion
during the first posting, the standards drafting team responded with “Testing multiple element
contingencies while accounting for system adjustments between each element outage will not yield any
facilities to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We
think the drafting team missed a basic point about the standard. The issue is not whether the registered
entity develops and documents corrective action plans TPL-003-0a R2 and R3. The issue is if the system
as currently designed meets the performance requirements in TPL-003-0a R1 which allows for operator
interventions on Category C3 contingencies. For those C3 contingencies that don’t currently meet the
performance obligations after operator interventions, the subject facilities would be included PRC-023-2

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
R6 list of facilities.

Response: Thank you for your comment.
1) Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address reliability
concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could lead to
instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due to transactions.
While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability.
The Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to instability,
uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as applicable circuits
under PRC-023-2.
The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC; however, the NERC Functional Model
does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year and beyond) with Transmission Planners,
Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and neighboring Planning Coordinators. Thus it is
appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to whether the monitored Facilities of a flowgate are
added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “long-term
reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude flowgates that
are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
2) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
MRO's NERC Standards Review
Subcommittee

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
confuses the matter and does not solve it. Reliability Coordinators add flowgates to manage real-time
congestion. Planning Coordinators do not. Per the NERC functional model, they do not even have a role
in deciding which flowgates to add to the IDC. Flowgates are added to the IDC to mitigate existing,
known congestion points not congestion points identified in a long-term planning study that may never
materialize due to changing conditions. Thus, IDC flowgates should be specifically excluded. Now let us
focus on the second component of flowgate. The second component is much like the first component in
that is it a mathematical construct to analyze the impact of power flows on the BES except is not required
to be included in the IDC. There is nothing in the definition of a flowgate to give credence that is
represents anything more that point to calculate power flows and the impact of transactions. Flowgates
are primarily used to manage congestion on the system and to sell transmission system. Because it is
convenient to select a group of lines as a proxy to sell transmission service or manage congestion does
not mean that those group of lines represent a reliability issue. Thus, we do not believe any flowgates
should be included in the list. Any true reliability issues can be identified through the TPL studies and
those facilities that do not meet the performance requirements are what should be used.
2) We do not support criterion B4. It exceeds what is required in the TPL standards and what is required per
the reliability directive in Order 729. The TPL standards allow system operator intervention for category
C3 contingencies between the two independent Category B contingencies. This standard should not
exceed those requirements in the TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the
relevant directives regarding the Planning Coordinator test. Paragraph 79 states that the test “must
include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in
transmission planning.” Paragraph 80 states that “the test must be consistent with the general reliability
principles embedded in the existing series of TPL” standards. Thus, exceeding the TPL standards could
be argued as deviating from the directive. In response to comments that did not support this criterion
during the first posting, the standards drafting team responded with “Testing multiple element
contingencies while accounting for system adjustments between each element outage will not yield any
facilities to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We
think the drafting team missed a basic point about the standard. The issue is not whether the registered
entity develops and documents corrective actions plans per TPL-003-0a R2 and R3. The issue is if the
system as currently designed meets the performance requirements in TPL-003-0a R1 which allows for
operator interventions on Category C3 contingencies. For those C3 contingencies that don’t currently
meet the performance obligations after operator interventions, the subject facilities would be included
PRC-023-2 R6 list of facilities.

Response: Thank you for your comment.
1) Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address reliability

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could lead to
instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due to transactions.
While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability.
The Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to instability,
uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as applicable circuits
under PRC-023-2.
The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC; however, the NERC Functional Model
does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year and beyond) with Transmission Planners,
Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and neighboring Planning Coordinators. Thus it is
appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to whether the monitored Facilities of a flowgate are
added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “long-term
reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude flowgates that
are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
2) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
Santee Cooper

The criteria in Attachment B lack clarity.
1) For example, B4 criterion for powerflow analysis does not specify a horizon.
2) In addition, in B1 does that only apply to circuits that are monitored by you or the IDC?
3) Assessing the post-contingency loading and determining if a facility rating is based on loading durations
of specified time periods is too burdensome and would not provide much value.

Response: Thank you for your comment.
1) The drafting team has modified criterion B4 to specify that the powerflow analysis is to be performed for the one-to-five-year planning horizon.
2) Criterion B1 applies to circuits monitored by the IDC.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

3) The purpose of the loadability standard is to ensure that protective relays are set to detect fault conditions but will not interfere with the system operators’
ability to take remedial action to protect system reliability. Simulations must be performed to assess the susceptibility to cascading outages to determine what
protective relays must be set in accordance with the relay loadability requirements.
Bonneville Power Administration

The evaluation method seems technically sound. The second category of applicable circuits, "Transmission
lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV ...", are not
considered BES elements based on the latest definition and BPA does not believe that this category of
circuits should be included.

Response: Thank you for your comment.
The drafting team understands the concern with including facilities operated below 100 kV; however, the NERC Statement of Compliance Registry Criteria does
allow Regional Entities the ability to identify such facilities operated below 100 kV as required to comply with NERC Reliability Standards. The drafting team has
replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which references text in section III.d.2 of the NERC
Statement of Compliance Registry Criteria. So the second category of circuits to be evaluated now refers to transmission lines and transformers operated below
100 kV “that are included on a critical facilities list defined by the Regional Entity.”
FirstEnergy

FE proposes that criterion B1 be removed from Attachment B. We support criterion B3 as written and
proposed revised versions of criterion B2 and B4.
1) a. Item B1 implies all facilities operated below 200kV and associated with a Flowgate must comply with
the PRC-023 standard. We support both MISO’s and PJM’s view that this criterion should be removed
since Flowgates in their truest sense is used for economic and market transmission needs over reliability
needs. Flowgates describe a designated point on the transmission system through which the Interchange
Distribution Calculator (IDC) calculates the power flow from Interchange Transactions. While its
recognized the drafting team attempted improve the Flowgate criteria by including a statement “that has
been included to address a long-term reliability concerns, as confirmed by the applicable Planning
Coordinator”, it is FE’s opinion that a Planning Coordinator does not play a role in adding or revising
Flowgates used in the IDC and do not utilize Flowgates for long-term reliability planning purposes.
Flowgates are a means of managing congestion and for identifying available transfer capability.
Continued use of this criterion will only serve to confuse and complicate matters.
2) b. Item B2 should be revised to include not only the monitored facilities associated with the IROL, but also
any “contingent” facilities that may describe the IROL condition. For example, it is important to include
the transmission facilities described in a NERC C3 contingency that may be associated with an IROL
definition. A C3 contingency describes a N-1-1 condition with system adjustments permitted in between
the 1st and 2nd contingency. It is necessary to ensure that the 2nd contingent facility does not
prematurely trip due to a relay loadability limitation. For greater consistency with terminology used in the

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
FAC-014 standard, Requirement R5.1 we propose the following for criterion B2: “B2. Each circuit
monitored as critical to the derivation of an IROL and each circuit associated with the Contingency(ies)
that describe the need for the IROL.”
3) c. We support criterion B3 as written.
4) d. In regards to criterion B4, FE supports the team’s recommendation for the Planning Coordinator to
perform a modified NERC Category C3 analysis to further identify sub 200kV facilities applicable to the
PRC-023 standard. However, the sub-bullets identifying various loading thresholds depending on the
Facility rating is overly complicated and creates undue burden for the Planning Coordinator performing
the study. We propose that the team simplify this criterion to clarify the applicable facilities are those that
exceed 130% of their continuous emergency rating for the modified NERC Category C3 test.

Response: Thank you for your comment.
1) Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address reliability
concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could lead to
instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due to transactions.
While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability.
The Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to instability,
uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as applicable circuits
under PRC-023-2.
The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC; however, the NERC Functional Model
does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year and beyond) with Transmission Planners,
Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and neighboring Planning Coordinators. Thus it is
appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to whether the monitored Facilities of a flowgate are
added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “long-term
reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude flowgates that
are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
2) The drafting team appreciates this suggestion, but believes that the circuits identified through criterion B2 should be the monitored Facilities that comprise an
IROL; if a contingent Facility could have an impact on the BES the circuit would be included as a monitored Facility or identified through another criterion in
Attachment B.
3) Thank you for your support.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

4) The drafting team proposed multiple thresholds to account for the thermal characteristics of equipment and variations in Facility Rating methodologies to avoid
an overly conservative, one-size-fits-all approach. Based on industry feedback, the drafting team has elected not to prescribe a single threshold value, but to
allow the flexibility as provided in the existing draft attachment.
IRC Standards Review
Committee

1) We disagree with B1 which includes monitored elements of flowgates. Flowgates may not always be
used for reliability purposes and may be temporary to address certain economic conditions. While we
appreciate the drafting team’s effort to refine the flowgate criteria from the last posting, the modifications
do not go far enough and still do not reflect the use of flowgates. NERC’s definition of flowgate includes
two components. Let’s focus on the first component which represents those flowgates defined in the IDC.
Because IDC flowgates list is updated monthly and the IDC users can add temporary flowgates to the IDC
at any time, this is an inappropriate list to use. We appreciate the drafting team’s attempt to resolve this
issue by including the caveat “that has been included to address long-term reliability concerns, as
confirmed by the applicable Planning Coordinator.” However, this really only confuses the matter and
does not solve it. Reliability Coordinators add flowgates to manage real-time congestion. Planning
Coordinators do not. Per the NERC functional model, they do not even have a role in deciding which
flowgates to add to the IDC. Flowgates are added to the IDC to mitigate existing, known congestion
points not congestion points identified in a long-term planning study that may never materialize due to
changing conditions. Thus, IDC flowgates should be specifically excluded. Now let us focus on the
second component of flowgate. The second component is much like the first component in that is it a
mathematical construct to analyze the impact of power flows on the BES except is not required to be
included in the IDC. There is nothing in the definition of a flowgate to give credence that is represents
anything more that point to calculate power flows and the impact of transactions. Flowgates are primarily
used to manage congestion on the system and to sell transmission system. Because it is convenient to
select a group of lines as a proxy to sell transmission service or manage congestion does not mean that
those group of lines represent a reliability issue. Thus, we do not believe any flowgates should be
included in the list. Any true reliability issues can be identified through the TPL studies and those
facilities that do not meet the performance requirements are what should be used.
2) We do not support criterion B4. It exceeds what is required in the TPL standards and what is required per
the reliability directive in Order 729. The TPL standards allow system operator intervention for category
C3 contingencies between the two independent Category B contingencies. This standard should not
exceed those requirements in the TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the
relevant directives regarding the Planning Coordinator test. Paragraph 79 states that the test “must
include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in
transmission planning.” Paragraph 80 states that “the test must be consistent with the general reliability
principles embedded in the existing series of TPL” standards. Thus, exceeding the TPL standards could
be argued as deviating from the directive. The directive is to be consistent not exceed. Exceeding the

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
TPL standards is not consistency. In response to comments that did not support this criterion during the
first posting, the standards drafting team responded with “Testing multiple element contingencies while
accounting for system adjustments between each element outage will not yield any facilities to be subject
to PRC-023 as long as TPL-003 system performance requirements are met.” We think the drafting team
missed a basic point about the standard. The issue is not whether the registered entity develops and
documents corrective action plans TPL-003-0a R2 and R3. The issue is if the system as currently
designed meets the performance requirements in TPL-003-0a R1 which allows for operator interventions
on Category C3 contingencies. For those C3 contingencies that don’t currently meet the performance
obligations after operator interventions, the subject facilities would be included PRC-023-2 R6 list of
facilities. Note: CAISO does not sign on to the above comments.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

lines remaining in service would not inappropriately trip the lines.
Tennessee Valley Authority

The NERC Glossary defines a flowgate as:1.) A portion of the Transmission system through which the
Interchange Distribution Calculator calculates the power flow from Interchange Transactions.2.) A
mathematical construct, comprised of one or more monitored transmission Facilities and optionally one or
more contingency Facilities, used to analyze the impact of power flows upon the Bulk Electric System. The
IDC flowgates change often thus making it difficult to coordinate those changes with the critical lines list
provided by the Planning Coordinator in Attachment B section B1. We assume that No. 2 above is the
definition that the SDT was referring. However, for clarity, we recommend that either the word “flowgate” be
specifically defined in Attachment B or removed.

Response: Thank you for your comment.
Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address reliability
concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could lead to instability,
uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due to transactions. While
Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability.
The Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to instability,
uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as applicable circuits under
PRC-023-2.
The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC; however, the NERC Functional Model does
indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year and beyond) with Transmission Planners, Reliability
Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and neighboring Planning Coordinators. Thus it is appropriate that
Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to whether the monitored Facilities of a flowgate are added to the list of
circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “long-term
reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude flowgates that
are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
New York Power Authority

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
2) B3. This item indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement
by the plant and the Transmission Entity it should be removed from Attachment B and placed elsewhere
in the document. If this is intended to apply to the Planning Coordinator, Transmission Entity should be
replaced with Planning Coordinator. Why does B3 only apply to Nuclear Power Plants?
3) B4. This criterion is overly stringent and should be deleted. The system is neither planned nor operated
to allow for two overlapping outages without operator action in between. If this criterion is retained, it
should be made consistent with the requirements of TPL-003 where operator actions can be assumed
between the first and second contingencies. Since a similar comment was made previously, more
information is being provided following.1. Since the system is neither planned nor operated to two
overlapping outages in between, such testing may result in unsolved cases, or voltages well below
criteria. In the case of an unsolved case, there are no flows to evaluate, making this standard impossible
to apply. In the case of a solved case with voltages well below criteria, currents are likely to be incredibly
high and therefore viewed as unrealistic. These concerns may limit the contingency selection to those
which are not severe, eliminating any perceived benefit from this testing.2. There is no guidance provided
on how the system should be dispatched in the model upon which the overlapping contingencies are
tested. This will result in significant discrepancies between the base assumptions used by the various
Planning Coordinators. The contents of this standard should be reviewed to reflect the new definition of
the Bulk Electric System.

This criterion applies to the Planning Coordinator and requires that the Planning Coordinator include circuits that form a path “(as agreed to by the plant
owner and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs) pursuant to
NUC-001” on the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes the
added reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.

3) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

lines remaining in service would not inappropriately trip the lines.
Manitoba Hydro

In Attachment B and the standard, there’s discussion of 15 min., up to 4 hour, 4-8 hour and more than 8 hour
ratings. This is very prescriptive and doesn’t match the requirements in the Facility rating methodology
standard or the model building limitations. It seems there is a disconnect between the FAC, TPL and PRC
standards.

Response: Thank you for your comment.
The drafting team proposed multiple thresholds to account for the thermal characteristics of equipment and variations in Facility Rating methodologies to avoid an
overly conservative, one-size-fits-all approach. The drafting team does not believe that there is a conflict between Attachment B and the FAC and TPL standards.
Rather, Attachment B recognizes differences in the rating methodologies developed pursuant to the FAC standards and their application in the TPL standards, and
accommodates these differences.
Lakeland Electric

Yes

NIPSCO

Yes

1) The method seems OK but the standard requirement R1 should be changed because lower voltage lines
have far more resistance and arc resistance needs to be included.
2) General Comments: We think that the proposed revised standard incorrectly assigns responsibility to the
PC instead of the TO,GO DP
3) Also, the new standard forces compliance on lower voltage lines which would limit protection of
equipment which will ultimately lead to many fewer networked lines and a less reliable electric system.

Response: Thank you for your comment.
1) The drafting team understands your concern and will place this item in the issues database for future consideration in the next general revision of the
standard.
2) The Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform the assessment in
Attachment B. The drafting team also notes that assigning this responsibility to the Planning Coordinator is consistent with the approved PRC-023-1 and
FERC Order No. 733.
3) Compliance with PRC-023-2 can be achieved without limiting protection of equipment or necessitating that networked lines be operated radially. The drafting
team notes that PRC-023-1 already applies to lines operated at 100 kV to 200 kV and PRC-023-2 only provides a uniform method by which Planning
Coordinators will identify circuits for which applicable entities must comply. Although PRC-023-2 does pertain to certain sub-100 kV circuits as directed in
Order No. 733, the drafting team does not believe that a significant number of sub-100 kV circuits will be impacted.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Western Area Power
Administration

Question 8 Comment
Is this necessary? Allow Planning Coordinators to do their jobs and decide which circuits are important.

Many facilities with voltages between 100 kV and 200 kV will only impact a well-defined local load region if
they trip. There is no risk of cascading outages beyond the local load region. The criteria in Attachment B
should allow these facilities to be dismissed from further evaluation.

1) B2. Item B2 adds significant confusion to the process. The long term planning horizon may include
transmission projects which have not even been built or alternative system configurations which do not
exist, making it impossible for affected parties to set their relays appropriately. Suggested replacement
language to avoid this issue: “Each circuit that is a monitored element of an IROL, assuming that all
transmission elements are in service and the system is under normal conditions.”
2) B3. This item indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement
by the plant and the Transmission Entity it should be removed from Attachment B and placed elsewhere
in the document. If this is intended to apply to the Planning Coordinator, Transmission Entity should be
replaced with Planning Coordinator.
3) B4. This criterion is overly stringent and should be deleted. The system is neither planned nor operated
to allow for two overlapping outages without operator action in between. If this criterion is retained, it
should be made consistent with the requirements of TPL-003 where operator actions can be assumed
between the first and second contingencies. Since a similar comment was made previously, more
information is being provided in this set of comments.1. Since the system is neither planned nor operated
to two overlapping outages in between, such testing may result in unsolved cases, or voltages well below

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
criteria. In the case of an unsolved case, there are no flows to evaluate, making this standard impossible
to apply. In the case of a solved case with voltages well below criteria, currents are likely to be incredibly
high and therefore viewed as unrealistic. These concerns may limit the contingency selection to those
which are not severe, eliminating any perceived benefit from this testing.2. There is no guidance provided
on how the system should be dispatched in the model upon which the overlapping contingencies are
tested. This will result in significant discrepancies between the base assumptions used by the various
Planning Coordinators.

Response: Thank you for your comment.
1) In response to several comments on this subject the drafting team has replaced the reference to “determined in the long-term planning horizon” with
“determined in the planning horizon pursuant to FAC-010.”
2) This criterion applies to the Planning Coordinator and requires that the Planning Coordinator include circuits that form a path “(as agreed to by the plant owner
and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC001” on the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes the
added reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
3) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
Duke Energy

1) B2 needs additional clarification, because identification could be in the short term or long term planning
horizon. Suggested rewording: “B2. Each circuit that is a monitored Element of an IROL where the IROL
was determined beyond the operating horizon.”
2) B3 needs additional clarification, to explicitly identify the necessary agreement between the plant owner
and Transmission Entity. Suggested rewording: “Each circuit that forms a path (as agreed to by the plant
owner and the Transmission Entity pursuant to NUC-001) to supply off-site power to nuclear plants.

Response: Thank you for your comment.
1) In response to several comments on this subject the drafting team has replaced the reference to “determined in the long-term planning horizon” with

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

“determined in the planning horizon pursuant to FAC-010.”
2) In response to comments on criterion B3 the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant Interface Requirements (NPIRs)
pursuant to NUC-001.”
Kansas City Power & Light

1) While we appreciate the drafting team’s effort to refine the flowgate criteria from the last posting, the
modifications do not go far enough and still do not reflect the use of flowgates. NERC’s definition of
flowgate includes two components. Let’s focus on the first component which represents those flowgates
defined in the IDC. Because IDC flowgates list is updated monthly and the IDC users can add temporary
flowgates to the IDC at any time, this is an inappropriate list to use. We appreciate the drafting team’s
attempt to resolve this issue by including the caveat “that has been included to address long-term
reliability concerns, as confirmed by the applicable Planning Coordinator.” However, this really only
confuses the matter and does not solve it. Reliability Coordinators add flowgates to manage real-time
congestion. Planning Coordinators do not. Per the NERC functional model, they do not even have a role
in deciding which flowgates to add to the IDC. Flowgates are added to the IDC to mitigate existing,
known congestion points not congestion points identified in a long-term planning study that may never
materialize due to changing conditions. Thus, IDC flowgates should be specifically excluded. Now let us
focus on the second component of flowgate. The second component is much like the first component in
that is it a mathematical construct to analyze the impact of power flows on the BES except is not required
to be included in the IDC. There is nothing in the definition of a flowgate to give credence that is
represents anything more that point to calculate power flows and the impact of transactions. Flowgates
are primarily used to manage congestion on the system and to sell transmission system. Because it is
convenient to select a group of lines as a proxy to sell transmission service or manage congestion does
not mean that those group of lines represent a reliability issue. Thus, we do not believe any flowgates
should be included in the list. Any true reliability issues can be identified through the TPL studies and
those facilities that do not meet the performance requirements are what should be used.
2) We do not support criterion B4. It exceeds what is required in the TPL standards and what is required per
the reliability directive in Order 729. The TPL standards allow system operator intervention for category
C3 contingencies between the two independent Category B contingencies. This standard should not
exceed those requirements in the TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the
relevant directives regarding the Planning Coordinator test. Paragraph 79 states that the test “must
include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in
transmission planning.” Paragraph 80 states that “the test must be consistent with the general reliability
principles embedded in the existing series of TPL” standards. Thus, exceeding the TPL standards could
be argued as deviating from the directive. The directive is to be consistent not exceed. Exceeding the
TPL standards is not consistency. In response to comments that did not support this criterion during the

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
first posting, the standards drafting team responded with “Testing multiple element contingencies while
accounting for system adjustments between each element outage will not yield any facilities to be subject
to PRC-023 as long as TPL-003 system performance requirements are met.” We think the drafting team
missed a basic point about the standard. The issue is not whether the registered entity develops and
documents corrective action plans TPL-003-0a R2 and R3. The issue is if the system as currently
designed meets the performance requirements in TPL-003-0a R1 which allows for operator interventions
on Category C3 contingencies. For those C3 contingencies that don’t currently meet the performance
obligations after operator interventions, the subject facilities would be included PRC-023-2 R6 list of
facilities.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

American Transmission
Company

Yes

Orange and Rockland Utilities,
Inc.

Question 8 Comment

Why does B3 only apply to Nuclear Power Plants only?

Response: Thank you for your comment.
This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes the added
reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
City of Jacksonville Beach, FL
dba/Beaches Energy Services

Yes

Attachment B, the criterion in B4 seems rather arbitrary; but, the numbers seem reasonable.

Include the following refinements to the criteria for determining the facilities that must comply with the
standard:

Response: Thank you for your support.
American Electric Power

1) Add new B5 that reads: “Each circuit that is operated below 100 kV that the Regional Entity has identified
as critical for the purposes of the Compliance Registry.”
2) Renumber B5 to B6.o Need to consider the amount of load that is placed at risk when determining
whether the circuit must comply with the standard. The threshold should be set at the DOE reporting
level of 300 MW.
3) Need to include a review and appeals process as part of the annual assessment for the Planning
Coordinator to review the proposed facilities with the transmission entity prior to adding those facilities to
the Planning Coordinator’s list of facilities that must comply with the standard.
Response: Thank you for your comment.
1) The drafting team believes it is appropriate to assess sub-100 kV circuits using the same methodology applied to Facilities operated at 100 kV to 200 kV.
Requiring applicable entities to comply for all sub-100 kV circuits included on a critical facilities list defined by the Regional Entity results in a higher standard
for sub-100 kV circuits, and is inconsistent with the directive in ¶60 of Order No. 733.
2) The criteria in Attachment B were selected to identify circuits that present a risk of cascading outages if relay loadability requirements are not met. The
drafting team believes this is a sufficient basis without requiring an assessment of the amount of load at risk. However, the drafting team has modified
criterion B5 in response to industry comments to require that if the Planning Coordinator selects a circuit based on technical studies or assessments, other

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

than those specified in criteria B1 through B4, that such selection is to be made in consultation with the Facility owner to provide the Facility owner an
opportunity for input into the assessment.
3) An appeals process will be included in the NERC Rules of Procedure so that a Facility owner may appeal a decision in the event it believes a circuit is
incorrectly identified by the Planning Coordinator
Nebraska Public Power District

Attachment B, Criteria B1 could add at least 24 transmission elements which are transmission lines operated
at 100kv to 200kv. After reviewing the MRO and SPP criteria these lines will not be included per PRC-023.
Loss of any of these lines will not cause a cascading outage which PRC-023 is intended to prevent.

Response: Thank you for your comment.
The drafting team has modified criterion B1 which may address the commenters concern. To the extent some of these circuits are still identified by criterion B1
the drafting team believes that these circuits do present the potential for cascading outages, although this potential may not be readily apparent when considering
loss of any one of these circuits individually.
An appeals process will be included in the NERC Rules of Procedure so that a Facility owner may appeal a decision in the event it believes a circuit is incorrectly
identified by the Planning Coordinator.
Great River Energy

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment
any flowgates should be included in the list. Any true reliability issues can be identified through the TPL
studies and those facilities that do not meet the performance requirements are what should be used.
2) We do not support criterion B4. It exceeds what is required in the TPL standards and what is required per
the reliability directive in Order 729. The TPL standards allow system operator intervention for category
C3 contingencies between the two independent Category B contingencies. This standard should not
exceed those requirements in the TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the
relevant directives regarding the Planning Coordinator test. Paragraph 79 states that the test “must
include or be consistent with the system simulations and assessments that are required by the TPL
Reliability Standards and meet the system performance levels for all Category of Contingencies used in
transmission planning.” Paragraph 80 states that “the test must be consistent with the general reliability
principles embedded in the existing series of TPL” standards. Thus, exceeding the TPL standards could
be argued as deviating from the directive. In response to comments that did not support this criterion
during the first posting, the standards drafting team responded with “Testing multiple element
contingencies while accounting for system adjustments between each element outage will not yield any
facilities to be subject to PRC-023 as long as TPL-003 system performance requirements are met.” We
think the drafting team missed a basic point about the standard. The issue is not whether the registered
entity develops and documents corrective actions plans per TPL-003-0a R2 and R3. The issue is if the
system as currently designed meets the performance requirements in TPL-003-0a R1 which allows for
operator interventions on Category C3 contingencies. For those C3 contingencies that don’t currently
meet the performance obligations after operator interventions, the subject facilities would be included
PRC-023-2 R6 list of facilities.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “long-term
reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude flowgates that
are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
2) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
Independent Electricity System
Operator

1) We commented on Criterion 6 (now B4) related to TPL-003 Category C contingencies in the previous
posting but we see no evidence that our comment was addressed. We therefore reiterate our position.
The PC and TP assess their future systems according to the performance requirements stipulated in the
TPL standards, including those in TPL-003. We question the requirement to have Planning Coordinators
assess the impact of double contingencies with no manual system adjustments in between since this is
not required by TPL-003. This goes beyond the basic planning and design requirements and in our view
should be removed from Criterion B4.
2) We also believe Criterion B4 should be rewritten for greater clarity. The second bullet seems
unnecessary since the post contingency loading on each circuit will not in fact be compared against its
Facility Rating to determine applicability of PRC-023-2 but against the corresponding “applicability
threshold”. Also, the third bullet seems to conflict with the fourth, since the forth bullet allows for
determining thresholds based on Facility Ratings that assume various loading durations, whereas the
third bullet links determination of the threshold to the Facility Rating for a duration nearest four hours only.
We therefore suggest the following alternative wording for B4:B4. Each circuit operated between 100 kV
and 200 kV identified by applying the following procedure:B4.1Establish Thresholds of Applicability - (text
of 4th bullet of B4)B4.2 Conduct Analysis - Conduct power flow analysis to simulate double contingency
combinations selected by engineering judgment as indicated in TPL-003 Category C3.B4.3 Evaluate
Applicability of PRC-023-2 - Compare post contingency loading of each circuit against its corresponding
threshold determined in B4.1. Indicate the applicability of standard PRC-023-2 to each circuit for which
the post contingency loading exceeds the corresponding threshold.B4.4 Exclusion - Radial circuits
serving only load are excluded.

Response: Thank you for your comment.

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

1) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
2) Thank you for your comment regarding Facility Rating versus evaluation thresholds. We have modified the attachment to add clarity. The attachment now
reads:
•

For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in consultation with the Facility owner, against a threshold
based on the Facility Rating assigned for that circuit and used in the power flow case by the Planning Coordinator.

Northeast Utilities

Yes

CenterPoint Energy

(a) Criterion B3 indicates any path that is used to supply off-site power to nuclear plants, as agreed to by the
plant owner and the Transmission Entity. If the purpose of attachment B is to provide “bright line” criteria,
then a negotiated agreement would not qualify as “bright line”. Additionally, off-site power requirements are
meant to ensure safe shutdown of nuclear reactors in a system restoration event where transmission lines are
lightly loaded. CenterPoint Energy recommends criterion B3 be deleted.
(b) Considering situations where the transmission system may be at risk of cascading outages or voltage
collapse, sub-200 kV elements should be considered operationally significant only whenever reasonably
contemplated scenarios would cause high amperage and low voltage to be experienced on the elements.
Criteria B4.a in Attachment B proposes loading exceeding 115% of a two or four hour rating following a
double contingency, without manual system adjustments. CenterPoint Energy believes this is not a
technically sound method to indicate if an element is operationally significant.

Response: Thank you for your comment.
(a) In response to comments on criterion B3 the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant Interface Requirements (NPIRs)
pursuant to NUC-001.” The drafting team believes this modification to criterion B3 provides a level of measurability that should address the commenter’s
concern.
(b) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect

January 24, 2011

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
New York Independent System
Operator

1) Flowgates are primarily used to manage congestion on the system and to sell transmission system.
Because it is convenient to select a group of lines as a proxy to sell transmission service or manage
congestion does not mean that those group of lines represent a reliability issue. Thus, flowgates should
not be included in the list as currently specified in B1. Any true reliability issues can be identified through
the TPL studies and those facilities that do not meet the performance requirements are what should be
applicable here.
2) B2 adds significant confusion to the process. The long term planning horizon may include transmission
projects which have not even been built or alternative system configurations which do not exist, making it
impossible for affected parties to set their relays appropriately. Suggested replacement language to avoid
this issue: “Each circuit that is a monitored element of an IROL, assuming that all transmission elements
are in service and the system is under normal conditions.”
3) B3 indicates that the circuits to be considered are to be agreed to by the plant owner and the
Transmission Entity. Attachment B is applicable to the Planning Coordinator. If this item is by agreement
by the plant and the Transmission Entity it should be removed from Attachment B and placed elsewhere
in the document. If this is intended to apply to the Planning Coordinator, Transmission Entity should be
replaced with Planning Coordinator.
4)

The B4 criterion is overly stringent and should be deleted. The system is neither planned nor operated to
allow for two overlapping outages without operator action in between. Paragraphs 79 and 80 of FERC
Order 729 contain the relevant directives regarding the Planning Coordinator test. Paragraph 79 states
that the test “must include or be consistent with the system simulations and assessments that are
required by the TPL Reliability Standards and meet the system performance levels for all Category of
Contingencies used in transmission planning.” Paragraph 80 states that “the test must be consistent with
the general reliability principles embedded in the existing series of TPL” standards. If this criterion is
retained, it should be made consistent with the requirements of TPL-003 where operator actions can be
assumed between the first and second contingencies.

January 24, 2011

100

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability.
The Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to instability,
uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as applicable circuits
under PRC-023-2.
The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC; however, the NERC Functional Model
does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year and beyond) with Transmission Planners,
Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and neighboring Planning Coordinators. Thus it is
appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to whether the monitored Facilities of a flowgate are
added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “long-term
reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude flowgates that
are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
2) In response to several comments on this subject the drafting team has replaced the reference to “determined in the long-term planning horizon” with
“determined in the planning horizon pursuant to FAC-010.”
3)

4) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
Consolidated Edison Co. of NY,
Inc.

Attachment B - Why does B3 only apply to Nuclear Power Plants only?

January 24, 2011

101

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
Ameren

1) Criterion B1, which has been modified to encompass only flowgates which have been included to address
long-term reliability concerns, while a step in the right direction, does not go far enough. Because
flowgates are primarily utilized to manage congestion and assist in the process of transmission service
sales, rather than investigate reliability issues more appropriately conducted via study work covered
under the TPL standards, this criteria should be eliminated.
2) Criterion B4 as worded still exceeds the requirements of Reliability Standard TPL-003 by requiring
simulating double contingencies with no operator intervention permitted. While such simulation would be
done as part of assessment work under TPL-003 for fast-acting contingencies involving multiple circuits,
such as Category C1 bus faults, C2 breaker failures, and C5 double-circuit tower outages, such
simulations are not necessary under TPL-003 with Category C3 events which consist of separate
Category B events with intervening operator action. Such simulations should not be made necessary as
part of the proposed PRC-023-2 standard. Rather, should the TPL-003 performance requirements not be
met for Category C3 contingencies with operator intervention considered, those facilities could be
included in the list of facilities specified in PRC-023-2 Requirement R6.

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Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

2) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen to
determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect
the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied
without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the
lines remaining in service would not inappropriately trip the lines.
National Grid

1. As per Section 4.2.3 (also included as bullet point 2 of Applicable circuits in Attachment B) "Transmission
Lines operated below 100 kV that Regional Entities have identified as critical facilities for the purposes of the
Compliance Registry and the Planning Coordinator has determined are required to comply with this standard."
National Grid believes that voltage levels less than 100 kV are outside NERC's jurisdiction and hence,
requirements related to sub 100 kV levels should not be part of NERC standards.
2. National Grid recommends a provision in the standard which allows entities an option to 1. Either comply
with standard for all applicable elements or 2. Apply the methodology as stated in Attachment B. The rationale
is that entities that choose to comply with PRC-023 for all applicable elements should be recognized and
should be exempted from complying with the methodology in Attachment B.
3. Requirement R6 of the proposed standard requires entities to apply criteria in Attachment B and conduct
assessments with no more than 15 months between assessments to determine which transmission elements
must comply with this standard. TPL standard which is considered to be the primary standard dealing with
designing and planning of the system allows an interim assessment to rely on previous years simulations and
does not mandate a stringent 15 month period between assessments. National Grid believes that an auxiliary
PRC-023 standard should not present more stringent requirements than the primary TPL standard and
recommends to remove the "15 month between assessments" requirement.

Response: Thank you for your comment.
1) The drafting team understands the concern with including facilities operated below 100 kV; however, the NERC Statement of Compliance Registry Criteria
does allow Regional Entities the ability to identify such facilities operated below 100 kV as required to comply with NERC Reliability Standards. The drafting
team has replaced the phrase “critical for the purposes of the Compliance Registry” with text from the ¶60 of Order No. 733, which references text in section
III.d.2 of the NERC Statement of Compliance Registry Criteria. So the second category of circuits to be evaluated now refers to transmission lines and
transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team made corresponding
modifications to the Applicability section.
2) The drafting team has added a new criterion B6 to include any circuit mutually agreed upon for inclusion by the Planning Coordinator and the Facility owner.
Any circuit identified by criterion B6 would not require application of the other criteria in Attachment B.

January 24, 2011

103

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

3) The drafting team intended that an assessment be performed each year, but that the power flow analyses used to support the assessment need not be
performed unless material changes to the system have occurred since the last assessment. The drafting team has added a footnote to criterion B4 to clarify
this intent.
ERCOT ISO

1) In regards to criteria B1, the Texas Interconnection does not have comparable monitored elements. All
transmission elements are treated and monitored equally in ERCOT at this time. The only exception to
this is IROLs which are already covered in criteria B2. Therefore, ERCOT ISO suggests removing the
reference to the Texas Interconnection in criteria B1.
2) In regards to criteria B3, the Planning Coordinator does not necessarily know the circuit paths for off-site
power for nuclear plants. The Transmission Owners would be better able to identify these circuits.
ERCOT ISO suggests moving this criteria into section 4.2 (Applicability, Facilities).
3) ERCOT ISO also suggests revising the language so that it does not state that a “circuit must comply with
the standard” since it is an entity that must comply with the standard. ERCOT ISO suggests replacing
this language with “circuit will be applicable to this standard” throughout Attachment B.

Response: Thank you for your comment.
1) The reference to the Texas Interconnection has been removed. The drafting team agrees that in the Texas Interconnection criterion B2 will identify the
appropriate circuits.
2) In response to comments on criterion B3 the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant Interface Requirements (NPIRs)
pursuant to NUC-001.” The drafting team believes this list of facilities is available to the Planning Coordinator.
3) The drafting team has modified the document as suggested to reflect that the applicable entities are responsible for complying with the standard. The
introductory sentence in Attachment B now reads, “If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for that
circuit.”
MidAmerican Energy

Criterion B1 should be eliminated as there is no technical basis to show that "flowgates" are anything more
than a measure of congestion. The loss or potential loss of a flowgate won't necessarily result in any more or
less reliability impact to the BES than the loss of any other BES element. Therefore a superior criteria for
Attachment B is to actually base critical elements upon the Federal Power Act Section 215 criteria of
instability, uncontrolled separation, or cascading, which is related to the B2 criteria and being an IROL.
Measuring the potential exceedance of TPL criteria as written is also acceptable. MidAmerican notes the
NERC Attachment B criteria exceed the FERC directive to follow TPL criteria in Order 729.

Response: Thank you for your comment.
Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address reliability

January 24, 2011

104

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

B1) The NERC book of flowgates for the Eastern Interconnection includes a combination of permanent and
temporary flowgates. This criterion should only use the permanent flowgates and the text should be modified
as indicated to reflect that. Each circuit that is a monitored Element of a permanent flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or
a comparable monitored Element in the Texas Interconnection or Québec Interconnection, that has been
included to address long-term reliability concerns, as confirmed by the applicable Planning Coordinator.
B3) This appears to link to the NUC-001 standard. We would suggest the following modification:"Each circuit
that forms a path (as agreed to by the plant owner and the Transmission Entity) to supply off-site power to
nuclear plants as established in the NPIR for NUC-001."
B5) We suggest removing this one as it is too open-ended and open to interpretation as to which additional
circuits should be considered. If there are additional criteria that are determined later that should be included,
then we suggest they be added by either a regional standard or a SAR to modify the NERC standard.

Response: Thank you for your comment.
B1) The drafting team has modified criterion B1 based on a number of comments related to temporary versus permanent flowgates. The drafting team believes
these modifications address the commenter’s concern.
B3) Thank you for your suggestion. In response to comments on criterion B3 the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant

January 24, 2011

105

Consideration of Comments on Relay Loadability Order 733 — Project 2010-13

Organization

Yes or No

Question 8 Comment

Interface Requirements (NPIRs) pursuant to NUC-001.”
B5) The drafting team has modified criterion B5 in response to industry comments to require that if the Planning Coordinator selects a circuit based on technical
studies or assessments, other than those specified in criteria B1 through B4, that such selection is to be made in consultation with the Facility owner to provide the
Facility owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure so that a Facility
owner may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.

January 24, 2011

106

Standards Announcement
Ballot Pool Open November 1 – December 2, 2010
Comment Period Open November 1 – December 16, 2010
Now available at: http://www.nerc.com/filez/standards/SAR_Project%202010-

Standards Announcement
Initial Ballot Open December 7 – 16, 2010
Project 2010-13: Revisions to Relay Loadability for Order 733
Available December 7th at: https://standards.nerc.net/CurrentBallots.aspx
Initial Ballot Window: December 7-16, 2010
An initial ballot for PRC-023-2 – Transmission Relay Loadability will be open from 8 a.m. Eastern on
December 7, 2010 through 8 p.m. Eastern on Thursday, December 16, 2010.
Instructions
During the initial ballot window, members of the ballot pool associated with this project may log in and
submit their votes from the following page: https://standards.nerc.net/CurrentBallots.aspx
Related Comment Period
A concurrent formal comment period is underway for PRC-023-2. Comments may be submitted using
this electronic form. The comment period and ballot will both end on December 16, 2010. More
information is available on the project page.
Next Steps
At the conclusion of the ballot period, the drafting team will consider all comments (those submitted with
a comment form, and those submitted with a ballot) and will determine whether to make additional
changes to the standard. The team will post its response to comments and, if the standard has only minor
changes, will post the standard and conduct a 10-day recirculation ballot.
Project Background
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it directed
several changes to that standard and also directed development of one or more new standards within
specified time periods. NERC filed for clarification and rehearing asking for clarity and an extension of
time to address the directives; however, without a response to the requests for clarification and rehearing,
NERC must progress as though these requests will be denied.
The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases.
Phase I addresses the specific directives from Order 733 that identified required modifications to various
elements within PRC-023-1. Phase II addresses directives associated with development of a new standard
to address generator relay loadability. Phase III addresses directives associated with writing requirements
to address protective relay operations due to power swings.
Applicability of Proposed PRC-023-2
Distribution Providers that own specific facilities (see standard for details)
Generator Owners that own specific facilities (see standard for details)

Planning Coordinators
Transmission Owners that own specific facilities (see standard for details)
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder participation.
We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

NERC Standards

Newsroom • Site Map • Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2010-13_Revisions to Relay Loadability for Order 733_in

Password

Ballot Period: 12/7/2010 - 12/16/2010
Ballot Type: Initial

Total # Votes: 286

Total Ballot Pool: 325
Quorum: 88.00 % The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
51.51 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.

Home Page
Summary of Ballot Results

Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

97
11
73
21
67
38
0
7
5
6
325

#
Votes

1
0.9
1
1
1
1
0
0.5
0.2
0.5
7.1

#
Votes

Fraction

47
1
30
10
29
17
0
2
2
2
140

Negative
Fraction

0.573
0.1
0.577
0.667
0.592
0.548
0
0.2
0.2
0.2
3.657

Abstain
No
# Votes Vote

35
8
22
5
20
14
0
3
0
3
110

0.427
0.8
0.423
0.333
0.408
0.452
0
0.3
0
0.3
3.443

6
1
9
4
10
3
0
1
2
0
36

9
1
12
2
8
4
0
1
1
1
39

Individual Ballot Pool Results

Segment
1
1
1
1
1
1
1
1

Organization

Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
APS
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.

Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Barbara McMinn
Robert D Smith
John Bussman
Scott Kinney

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Ballot
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Comments
View
View
View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Manitoba Hydro
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Omaha Public Power District
Oncor Electric Delivery
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.

Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Kevin L Howes

Affirmative
Negative
Negative
Negative
Negative

View
View

Negative

View

Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Gregory Campbell
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Harold Taylor, II
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

View

Robert Solomon

Affirmative

Ajay Garg
Ronald D. Schellberg

Negative
Affirmative

View

Negative

View

Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Martyn Turner
Joe D Petaski
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch

Negative
Affirmative
Affirmative
Affirmative
Abstain

View
View
View

Randy MacDonald

Negative

Chang G Choi

Michael Moltane

Arnold J. Schuff
David H. Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Douglas G Peterchuck
Michael T. Quinn
Daryl Hanson
Chifong L. Thomas
Colt Norrish
Ronald Schloendorn
John C. Collins
Frank F. Afranji
David Thorne
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Catherine Koch
John C. Allen

https://standards.nerc.net/BallotResults.aspx?BallotGUID=e36db32f-a12b-40c9-83a6-553a9f92247c[1/12/2011 4:30:20 PM]

Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative

Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative

View
View
View

View

View
View
View
View
View
View

View
View

View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Anaheim Public Utilities Dept.
APS
Arkansas Electric Cooperative Corporation
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Power Agency
Bonneville Power Administration
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Farmington
City of Green Cove Springs
City of Leesburg
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Power Corporation

Tim Kelley
Robert Kondziolka
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Long T Duong
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Frank J. Owens
James W. Beck
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Kelly Nguyen
Steven Norris
Philip Huff
James V. Petrella
Robert Lafferty
Pat G. Harrington
Duane S. Dahlquist
Rebecca Berdahl
Thomas C Duffy
Steve Alexanderson
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Michelle A Corley
Bruce Krawczyk
Peter T Yost
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Joe McKinney
Lee Schuster

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Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain

View
View

Affirmative
Negative
Affirmative
Affirmative

Affirmative

Negative

View

Negative
Affirmative
Negative
Affirmative
Negative
Abstain

View
View
View
View
View

Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative

View
View
View
View
View
View
View

Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View

Negative

View
View

View

Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative

View
View
View

View
View

View

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5

Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Public Power Association
Arkansas Electric Cooperative Corporation
Central Lincoln PUD
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.

Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
David L Kiguel
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
David Burke
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
Hubert C. Young
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
James R. Keller
Michael Ibold
Kenneth Goldsmith
Allen Mosher
Ronnie Frizzell
Shamus J Gamache

Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative

Timothy Beyrle

Affirmative

View

Negative
Negative

View
View

Affirmative
Affirmative
Abstain
Affirmative
Negative

View
View

David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Douglas Hohlbaugh
Henry E. LuBean

View

Affirmative
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Negative

View
View

View

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Abstain
Affirmative
Affirmative
Negative

John D. Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Edwin B Cano

Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=e36db32f-a12b-40c9-83a6-553a9f92247c[1/12/2011 4:30:20 PM]

View

View
View

View

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

AEP Service Corp.
Amerenue
APS
Avista Corp.
Bonneville Power Administration
City and County of San Francisco
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Consolidated Edison Co. of New York
Consumers Energy
Covanta Energy
Cowlitz County PUD
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
El Paso Electric Company
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entergy Corporation
Exelon Nuclear
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MidAmerican Energy Co.
Nebraska Public Power District
New Harquahala Generating Co. LLC
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Public Utility District No. 1 of Lewis County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.

Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
Francis J. Halpin
Daniel Mason
Max Emrick
Alan Gale
Stephanie Huffman
Wilket (Jack) Ng
James B Lewis
Samuel Cabassa
Bob Essex
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Alfred W Morgan
Jack Cashin

Negative
Negative
Affirmative
Affirmative
Negative

View

Negative

View

Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative

Doug Ramey

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Christopher Schneider
Don Schmit
Nicholas Q Hayes
Gerald Mannarino
Tracy R Bibb
Michael K Wilkerson
Michelle DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Pete Ungerman
Annette M Bannon
Wayne Lewis
Jerzy A Slusarz
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Richard Jones
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Melissa Kurtz
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester

https://standards.nerc.net/BallotResults.aspx?BallotGUID=e36db32f-a12b-40c9-83a6-553a9f92247c[1/12/2011 4:30:20 PM]

View
View
View
View

Abstain

Stanley M Jaskot
Michael Korchynsky
David Schumann
Cynthia E Sulzer
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Dennis Florom
Charlie Martin
Mike Laney
S N Fernando
David Gordon

View

Abstain
Affirmative
Affirmative
Affirmative
Negative

View

Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain

View

View
View

NERC Standards
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Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
INTELLIBIND
JDRJC Associates
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
Oregon Public Utility Commission
Snohomish County PUD No. 1
Utah Public Service Commission
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool Regional Entity
Texas Reliability Entity

Liam Noailles
Edward P. Cox
Jennifer Richardson
Justin Thompson
Brenda S. Anderson
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
James D. Hebson
Hugh A. Owen
Trent Carlson
Claire Warshaw
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Michael C Hill
Marjorie S. Parsons

Negative
Negative

View
View

Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative

View
View
View

View
View

View

View
View
View

Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative

View

John Stonebarger
David F. Lemmons
Negative
Roger C Zaklukiewicz
Negative
James A Maenner
Abstain
Edward C Stein
Affirmative
Kevin Conway
Affirmative
Jim D. Cyrulewski
Negative
Brian Evans-Mongeon
Terry Volkmann
Negative
William Mitchell Chamberlain

View
View

Donald E. Nelson

View

Abstain

Jerome Murray
William Moojen
Ric Campbell
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Stacy Dochoda
Larry D. Grimm

https://standards.nerc.net/BallotResults.aspx?BallotGUID=e36db32f-a12b-40c9-83a6-553a9f92247c[1/12/2011 4:30:20 PM]

Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative

View
View

Negative

View

NERC Standards
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801

Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=e36db32f-a12b-40c9-83a6-553a9f92247c[1/12/2011 4:30:20 PM]

Standards Announcement

Initial Ballot Results
Project 2010-13 - Relay Loadability for Order 733
Now available at: https://standards.nerc.net/Ballots.aspx
An initial ballot of PRC-023-2 — Transmission Relay Loadability ended on December 16, 2010.
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results.
Ballot for Standard:
• Quorum: 88.00 %
• Approval: 51.51%
Project Background:
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it directed several
changes to that standard and also directed development of one or more new standards within specified time
periods. NERC filed a request for clarification and rehearing and requested additional time to address the
directives; however, pending FERC’s response to the requests for clarification and additional time, NERC
must progress as though these requests will be denied.

The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases. Phase I
addresses the specific directives from Order 733 that identified required modifications to various elements
within PRC-023-1. Phase II addresses directives associated with development of a new standard to address
generator relay loadability. Phase III addresses directives associated with writing requirements to address
protective relay operations due to power swings.
More details may be found on the project page:
http://www.nerc.com/filez/standards/SAR_Project%202010-13_Order%20733%20Relay%20Modifiations.html

Next Steps
The drafting team will consider all comments (those submitted with a comment form and those submitted with
a ballot) and will determine whether to make additional changes to the standard. The team will post its
response to comments and, if the standard has only minor changes, will post the standard and conduct a 10-day
recirculation ballot. The team will also conduct a non-binding poll of the VRFs and VSLs.
Ballot Criteria
Approval requires both (1) a quorum, which is established by at least 75% of the members of the ballot pool
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and negative
votes, excluding abstentions and non-responses.

Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

Consideration of Comments on Initial Ballot — Revisions to Relay Loadability for Order 733 (Project 2010-13)
Date of Initial Ballot: December 7-16, 2010
Summary Consideration: A 45-day formal comment period with a concurrent ballot during the last 10 days of the comment period was conducted for
the Transmission Relay Loadability Version 2 standard PRC-023-2 from November 1, 2010 to December 1-16, 2010 and achieved a quorum of 88.00% and a
weighted segment approval of 51.51%.
Commenters noted inconsistencies and redundancy between the Applicability section, Parts 6.1 and 6.2 of Requirement R6 and Attachment B. The drafting
team agrees that inconsistency between these sections of the standard will lead to confusion. The drafting team has removed parts 6.1 and 6.2 from
Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B based on industry comments to provide consistency and
clarity.
Commenters expressed concern that 24 months was not enough time to implement protection system modifications when the Planning Coordinator identifies
circuits for which the applicable entity must comply with the standard. The drafting team considered a number of comments regarding the implementation
timeframe and has extended the implementation time frame to 39 months to provide the Facility owners time to budget, procure, and install any protection system
equipment modifications and for consistency with PRC-023-1.
Commenters expressed concern with use of the phrase critical facilities for purposes of the Compliance Registry. The drafting team modified this reference
related to circuits operated below 100 kV by replacing the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which
references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria. The second category of circuits to be evaluated now refers to
transmission lines and transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.”
Commenters expressed concern with criterion 10 citing that additional specificity is necessary to clarify a number of issues. In response to comments the
drafting team added a footnote to criterion 10 to clarify that use of the phrase “mechanical withstand” is based on the “dotted line” in IEEE C57.109-1993 – IEEE
Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team also moved the requirement for fault protection
to a separate part of criterion 10 to clarify it applies only to load responsive transformer fault protection relays, and only when such relays are used.
Some commenters expressed concern that reporting associated with certain criteria under Requirement R1 duplicates requirements in FAC-008 and FAC-009.
The drafting team explained that the FAC standards pertain to developing and transmitting ratings and rating methodologies, whereas PRC-023 requires
notification when the certain Facility Ratings are used in assessing relay loadability
Some commenters expressed concern with complying with Requirement R2. The drafting team noted that Requirement R2 does not add a new obligation on
Transmission Owners, Generator Owners, and Distribution Providers; it only explicitly states in PRC-023-2 an obligation that presently is included in Attachment
A, Section 2 of PRC-023-1.
Some commenters questioned the need to differentiate between certain types communication-assisted protection systems. The drafting team noted that the
distinction in Attachment A, Section 1.6 is appropriate, because current -differential telecommunications systems are different than other telecommunications
systems, in that the sensitivities for the protection elements are often set very sensitively – well below load current – and depend on the integrity of the channel to
make a trip/no trip decision where other telecommunication system technologies require the operation of other protection system elements (usually distance
January 24, 2011

elements) which are already subject to the requirements of this standard. Therefore, they will trip immediately due to load current upon the loss of
communications, and are dependent on the fault detectors to inhibit trip.
Many commenters expressed their belief that flowgates are market-based tools that are not appropriate for use in assessing system reliability. The drafting team
responded that congestion and system reliability are not mutually exclusive concerns. Markets are constrained to ensure that the transmission system is
operated within physical system constraints that if violated, could lead to instability, uncontrolled separation, or cascading. While flowgates are used to manage
congestion, the underlying basis for doing so is to preserve system reliability. As such, it is appropriate and necessary to include monitored Facilities of flowgates
as applicable circuits under PRC-023-2.
Commenters indicated clarification is needed to identify which Interconnection Reliability Operating Limits (IROLs) are to be considered in application of
Attachment B, criterion B2. In response to several comments on this subject, the drafting team has replaced the reference to “determined in the long-term
planning horizon” with “determined in the planning horizon pursuant to FAC-010”.
A number of commenters expressed concern that the description of transmission paths that supply off-site power to nuclear power plants lacked measurability.
The drafting team has added a reference to Nuclear Plant Interface Requirements (NPIRs) developed pursuant to NUC-001. The drafting team also clarified that
this criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown.
The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies in Attachment B, criterion B4. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is
to be used as a screen to determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in
widening of the initiating outage if manual adjustments were not completed before the second contingency. The drafting team also clarified that while an
assessment must be performed each year, the power flow analyses used to support the assessment need not be performed unless material changes to the
system have occurred since the last assessment. The drafting team has added a footnote to criterion B4 to clarify this intent.
Commenters expressed concern that the criteria in Attachment B, criterion B5 in particular, provide too much autonomy to the Planning Coordinator. The drafting
team added to some of the criteria that the Planning Coordinator shall consult with the Facility owner when performing its assessment to provide the Facility
owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure so that a Facility owner
may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.
Several commenters expressed concern that Requirement R7 creates a potential for double jeopardy. The drafting team understands the double jeopardy
concern and has deleted Requirement R7. The Effective Dates section has been modified to address the timeline in which Facility owners must comply with
Requirements R1 and R5 when the Planning Coordinator identifies a circuit for which the Facility owner must comply with the standard.
One commenter requested that the exception for "switch on to fault" schemes be added back in. The drafting team understands the commenter’s concern that
the proposed implementation plan for PRC-023-2 had the unintended consequence of shortening the time provided for Facility owners to comply with
Requirement R1 for switch-on-to-fault schemes. The drafting team has modified the effective dates in the standard to address this problem.
A limited number of commenters expressed concern that the criteria for verifying relay loadability in Requirement R1 may not be directly applicable to circuits
operated below 100 kV. The drafting team understands this concern and this item has been placed in the issues database for future consideration in the next
general revision of the standard. The drafting team notes that PRC-023-1 already applies to lines operated at 100 kV to 200 kV and the drafting team does not
believe that a significant number of sub-100 kV circuits will be impacted. As such, the drafting team disagrees that more research is required prior to
implementing PRC-023-2.
January 24, 2011

If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious consideration in this
process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 609-452-8060 or at
1
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.

Voter

Entity

Roger C
Zaklukiewicz

Seg- Vote
ment

Comment

Concern with the possible interpretation of the wording in Requirement 1, Criteria 10. The
wording needs to be clarified.

Negative

Response: Thank you for your comment.
The text of the standard has been modified to clarify the intent of criterion 10. Specifically, a footnote has been added to criterion 10 to clarify that use of the
phrase “mechanical withstand” is based on the “dotted line” in IEEE C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current
Duration, Clause 4.4, Figure 4. The requirement for fault protection has been moved to a separate part of criterion 10 to clarify it applies only to load
responsive transformer fault protection relays, and only when such relays are used.
Edward P. Cox AEP Marketing
6
Negative
The following comments are a subset of those submitted during the comment period. For
Brock Ondayko

AEP Service Corp.

Paul B.
Johnson

American Electric
Power

Raj Rana

American Electric
Power

more comprehensive commentary, please see the comments provided during the
comment period.
1. R1's Criterion 10: American Electric Power sees two issues with R1's Criterion 10.
First, transformer "mechanical withstand capability" is undefined, vague, and subject to
various interpretations. The terminology used in this criterion must be more tightly
defined to prevent ambiguity or else referenced to some agreed-upon standard such as
IEEE C57.109-1993. Second, American Electric Power agrees that it is appropriate for
the 150% and 115% settings criteria to apply to line relays terminated only with a
transformer. However, Criterion 10 seems to assume that transmission line relays on
transmission lines terminated with a transformer are also typically intended to protect the
transformer. This is not normally or necessarily true. If the line relays are not intended to
protect the transformer and as long as the transformer relaying properly protects the
transformer from mechanical damage, there is no reason for Criterion 10 to apply to the
line relays. To address these two deficiencies in Criterion 10, American Electric Power
is providing proposed replacement language as part of its comments submission.
2. Sections 4.2.3, 4.2.6, 6.2, and the applicability portion of Attachment B: The wording

The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
January 24, 2011

under Sections 4.2.3, 4.2.6, 6.2, and the applicability portion of Attachment B needs to
be made consistent to avoid any misinterpretations and confusion. American Electric
Power is providing proposed replacement language as part of its comments submission.
3. Requirement 7: Need to provide a 60-month timeline to implement the noted
requirements for each facility that is added to the Planning Coordinator’s initial list of
facilities that must comply with this standard, versus the 24-month timeline to
implement the noted requirements for each facility that is added to the Planning
Coordinator’s established list of facilities that must comply with this standard. This is a
practical consideration that recognizes the high likelihood that the number of facilities
that will be identified during development of the initial list of facilities will be many
times greater than the incremental number of facilities that will be identified during the
annual assessments and added to the established list of facilities. In addition, need to
specify under this requirement whether any facilities that drop off the Planning
Coordinator’s list of facilities while still within the applicable (60-month or 24-month)
implementation timeline must still comply with this standard.
4. Attachment A, Section 1.6: The wording of Attachment A, section 1.6 needs to be
made consistent to avoid any confusion. American Electric Power is providing proposed
replacement language as part of its comments submission.
5. Attachment B: Need to include a review and appeals process as part of the annual
assessment for the Planning Coordinator to review the proposed facilities with the
transmission entity prior to adding those facilities to the Planning Coordinator’s list of
facilities that must comply with the standard. American Electric Power is providing
proposed replacement language as part of its comments submission.
Response: Thank you for your comments
1. The mechanical withstand is defined in IEEE C57.109-1993, IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, and a reference
to this standard has been added as a footnote to address your concerns. The drafting team has modified the text of the standard to make the consideration
of the mechanical withstand capability applicable to only the load responsive transformer fault protection relays, and only when such relays are used.
2. The drafting team agrees that inconsistency between these sections of the standard will lead to confusion. The drafting team has removed parts 6.1 and
6.2 from Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B based on industry comments to provide
consistency and clarity.
3. The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation time frame to 39
months to provide the Facility owners time to budget, procure, and install any protection system equipment modifications and for consistency with PRC-0231.
January 24, 2011

4. Section 1.6 has been modified essentially as is suggested in the comment.
5. The drafting team has added to some of the criteria that the Planning Coordinator shall consult with the Facility owner when performing its assessment to
provide the Facility owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure
so that a Facility owner may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.
Kirit S. Shah
Ameren Services
1
Negative
(1) Requirements R4 and R5 are already covered in Stanadrds FAC-008 and FAC-009.

So they are redundant here and should be removed.

Mark Peters

Ameren Services

(2) Section 6.2 is unclear and seems arbitrary in the statement ‘if the Regional Entity has
indentified either of these Element types as critical facilities for the purpose of the
Compliance registry’. A clear test is lacking.
(3) Section 1.6 is contrary to section 2.0 and seems arbitrary. Why is a communication
system for a current-based scheme treated to a higher standard than other
communications scheme? The communications scheme reliability is covered through the
maintenance and misoperations analysis standards.
(4) Criterion B1, which has been modified to encompass only flowgates which have
been included to address long-term reliability concerns, while a step in the right
direction, does not go far enough. Because flowgates are primarily utilized to manage
congestion and assist in the process of transmission service sales, rather than investigate
reliability issues more appropriately conducted via study work covered under the TPL
standards, this criteria should be eliminated.
(5) Criterion B4 as worded still exceeds the requirements of Reliability Standard TPL003 by requiring simulating double contingencies with no operator intervention
permitted. While such simulation would be done as part of assessment work under TPL003 for fast-acting contingencies involving multiple circuits, such as Category C1 bus
faults, C2 breaker failures, and C5 double-circuit tower outages, such simulations are not
necessary under TPL-003 with Category C3 events which consist of separate Category B
events with intervening operator action. Such simulations should not be made necessary
as part of the proposed PRC-023-2 standard. Rather, should the TPL-003 performance
requirements not be met for Category C3 contingencies with operator intervention
considered, those facilities could be included in the list of facilities specified in PRC023-2 Requirement R6.

Response: Thank you for your comments.
January 24, 2011

1. Providing this information to the specified entities addresses the potential for confusion as to the amount of time available to take corrective action. FAC008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the relay
loadability is based on a 15-minute rating.
2. The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B
(which used the same phrase) based on industry comments to provide clarity. The drafting team has replaced the phrase “critical for the purposes of the
Compliance Registry” with text from ¶60 of Order No. 733, which references text in section III.d.2 of the NERC Statement of Compliance Registry
Criteria. So the second category of circuits to be evaluated now refers to transmission lines and transformers operated below 100 kV “that are included
on a critical facilities list defined by the Regional Entity.” The test by which the Regional Entity may make this determination is outside the scope of this
standard.
3. Current-differential telecommunications systems are different than other telecommunications systems, in that the sensitivities for the protection elements
are often set very sensitively – well below load current – and depend on the integrity of the channel to make a trip/no trip decision where other
telecommunication system technologies require the operation of other protection system elements (usually distance elements) which are already subject
to the requirements of this standard. Therefore, they will trip immediately due to load current upon the loss of communications, and are dependent on the
fault detectors to inhibit trip.
4. Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address reliability
concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could lead to
instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due to
transactions. While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability.
The Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If
monitored Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading
to instability, uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as
applicable circuits under PRC-023-2.
The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC; however, the NERC Functional
Model does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year and beyond) with Transmission
Planners, Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and neighboring Planning Coordinators.
Thus it is appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to whether the monitored Facilities of a
flowgate are added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates and has replaced the reference to “longterm reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this more clearly reflects the intent to exclude
flowgates that are established on a temporary basis and more clearly identifies the role of the Planning Coordinator in applying criterion B1.
5. The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a
screen to determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in
widening of the initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that
the loadings respect the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of
line outages to be studied without manual system adjustment to ensure that, if the manual adjustments were not completed before the second
contingency, the relay settings on the lines remaining in service would not inappropriately trip the lines
January 24, 2011

Jason Shaver

American
Transmission
Company, LLC

Affirmative

Requirement R7 requires the Registered Entities to implement Requirement R1, Requirement R2,
Requirement R3, Requirement R4, and Requirement R5 for each facility that the Planning
Coordinator added to the list of facilities that must comply with this standard (per Requirement
R6) by certain dates following notification by the Planning Coordinator. ATC believes it is difficult
to determine without knowing the full scope of work. Until the Planning criteria can be
determined, the scope is unknown. Assuming not many assets are added, two years would be a
more reasonable amount of time.

Response: Thank you for your comments.
The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation time frame to 39
months to provide the Facility owners time to budget, procure, and install any protection system equipment modifications and for consistency with PRC-023-1.
Donald S.
Bonneville Power
1
Watkins
Administration
Rebecca
Bonneville Power
3
Berdahl
Administration
Francis J.
Bonneville Power
5
Halpin
Administration
Brenda S.
Bonneville Power
6
Anderson
Administration
Response: Thank you for your comments.

Negative

Please refer to formal BPA comments submitted for the period ending 12/16/10

Negative

Please refer to formal BPA comments submitted for period ending 12/16/10

Negative

Please refer to BPA's formal comments submitted separately.

Negative

Please refer to formal BPA comments submitted for this comment period.

Please refer to the drafting team responses in the Consideration of Comments document.
Gregory Van
California ISO
2
Negative
With regard to the questions asked in the comment form, the CAISO answers and comments
Pelt
are:
Q1 - Yes
Q2 - No comment from the PC perspective. The TOs are responsible for designing phase
protection schemes appropriate to their systems.
Q3 - No comment from the PC perspective. The facility owners are responsible
Q4 - No comment from the PC perspective. The facility owners are responsible

January 24, 2011

Q5 - No Comments: Wording for R 6.2 needs more clarity. Currently, only identifies the Regional
Entity as identifying critical facilities. Believe it should also include the Planning Coordinator as
an entity that may identify critical facilities operated below 100 kV. It is not clear how the
Planning Coordinator is supposed to know which facilities the Regional Entity has identified that
are below 100 kV that are part of the Bulk Electric System. This information is not readily
available and there is no requirement for the Regional Entity to communicate this information to
7

the Planning Coordinator. The concern is that inaction by the Regional Entity could cause the
Planning Coordinator to be out of compliance with this requirement. Additional clarity is needed
throughout requirement R6 and throughout the PRC-023-2 Standard.
Q6 - No Comments: This requirement could be construed as potential for double jeopardy
because failure to comply with Requirements 1-5 represent a violation of both Requirement 7
and Requirement 1-5.
Q7 - Yes
Q8 - No Comments: Additional clarity is needed in Attachment B and throughout the PRC-023-2
Standard.

Response: Thank you for your comments
Q1. Thank you for your comment
Q2. Thank you for your comment
Q3. Thank you for your comment
Q4. Thank you for your comment
Q5. The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy with the Applicability section and Attachment B. Within the
Applicability section and Attachment B, a number of modifications have been made based on industry comments to improve clarity. The drafting team
has replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which references text in section
III.d.2 of the NERC Statement of Compliance Registry Criteria, So the second category of circuits to be evaluated now refers to transmission lines and
transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team believes it is
necessary to maintain consistency with the NERC Statement of Compliance Registry Criteria for the Regional Entity to develop a critical facilities list,
and then have the Planning Coordinator apply the criteria in Attachment B to determine for which of the circuits on the list the applicable entities must
comply with the standard. While the drafting team acknowledges there is no requirement for the Regional Entity to provide the list, the drafting team
believes the Regional Entity will make a critical facilities list available as it is necessary for other entities to have this information to support reliable
operation of the interconnected transmission grid.,
Q6. The drafting team understands the double jeopardy concern and has deleted Requirement R7. The Effective Dates section has been modified to
address the timeline in which Facility owners must comply with Requirements R1 and R5 when the Planning Coordinator identifies a circuit for which the
Facility owner must comply with the standard.
Q7. Thank you for your comment
Q8. Extensive revisions were made to Attachment B and throughout the standard to improve clarity.

January 24, 2011

Paul Rocha

CenterPoint Energy

Negative

CenterPoint Energy has several concerns with this proposed Standard. CenterPoint
Energy’s main concern is with the criteria in Attachment B used to determine which
facilities must comply.
1. We do not agree with criterion B4 that a percent loading is a technically sound basis to
indicate if a facility is operationally significant. CenterPoint Energy recommends the
threshold be revised to apply to those facilities that the loss of which would risk
cascading outages or voltage collapse.
2. Criterion B3 indicates any path that is used to supply off-site power to nuclear plants,
as agreed to by the plant owner and the Transmission Entity. If the purpose of
attachment B is to provide “bright line” criteria, then a negotiated agreement would not
qualify as “bright line”. Additionally, off-site power requirements are meant to ensure
safe shutdown of nuclear reactors in a system restoration event where transmission lines
are lightly loaded. CenterPoint Energy recommends it be deleted.
3. CenterPoint Energy recommends criterion B5 be deleted, as it is too broad and gives
the PC too much discretion in determining other facilities which must comply with this
Standard. In addition, CenterPoint Energy believes Transmission Planners should have a
role in the determination of which facilities must comply with this standard.
4. The use of the term “critical” in R6 is problematic, as it can cause confusion with
NERC CIP Standards which require the facility owner to determine Critical Assets.
CenterPoint Energy recommends using “operationally significant” wherever “critical” is
used.

Response: Thank you for your comments.
1. The purpose of the criteria in Attachment B is to identify circuits that present a risk of cascading outages if relay loadability requirements are not met.
Applying criterion B4 only to circuits for which their loss would risk cascading outages or voltage collapse would create circularity in the assessment by
requiring the Planning Coordinator to know the outcome before applying the criteria.
2. In response to comments on criterion B3 the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant Interface Requirements
(NPIRs) pursuant to NUC-001.” The drafting team believes this modification to criterion B3 provides a level of measurability that should address the
commenter’s concern.
3. The drafting team has modified criterion B5 in response to industry comments to require that if the Planning Coordinator selects a circuit based on technical
studies or assessments, other than those specified in criteria B1 through B4, that such selection is to be made in consultation with the Facility owner to
provide the Facility owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of Procedure so
that a Facility owner may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator. The drafting team believes
January 24, 2011
9

the Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform the assessment in
Attachment B. The drafting team also notes that assigning this responsibility solely to the Planning Coordinator is consistent with the approved PRC-023-1
and FERC Order No. 733.
4. The context in which the term “critical” is used is different than in the NERC “Zone 3” and “Beyond Zone 3” reviews. The remaining references to the term
critical are in the context of NERC Statement of Compliance Registry Criteria. Rather than using the term “operationally significant,” the drafting team has
replaced the phrase “critical for the purposes of the Compliance Registry” with text from ¶60 of Order No. 733, which references text in section III.d.2 of
the NERC Statement of Compliance Registry Criteria, so the second category of circuits to be evaluated now refers to transmission lines and transformers
operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team made corresponding modifications to
the Applicability section.
Shamus J
Central Lincoln PUD 4
Negative
Central Lincoln supports the Pacific Northwest Small Public Power Group comments:
Gamache

1. The comment group finds R1.10 very confusing when attempting to understand it in
the context of IEEE C57.109-1993. C57.109 identifies a solid curve as the thermal
damage curve, while a dotted dog leg is the mechanical damage curve. Generally the dog
leg is only considered for those class II and III transformers subjected to frequent
through faults and all class IV transformers. Is the intent of the SDT to require this level
of protection for all transformers regardless of through fault frequency and/or
transformer class? If the SDT really meant to protect transformers from thermal or
combination damage, please note that it is not possible to completely protect
transformers from the thermal damage of low current long duration faults while still
complying with the 150% of maximum rating. The thermal damage curve extends down
to twice the base current. A footnote in C57.109 states that base current is established
from the lowest nameplate kVA rating. A typical transformer with two stages of cooling
will have a high nameplate rating of 1.67 times this base rating. The first bullet of R1.10
states affected entities must allow 1.5 times the maximum, so we are up to 2.5 times the
base rating. Since we must allow this much without tripping, the relay must be set even
higher. 1.2 times would be a secure margin, so the relay is set to pickup at 3 times the
base rating. This setting would of course violate the first part of R1 criterion 10 because
the transformer’s fault capability would be exceeded for faults between 2 and 3 times the
base rating.
2. We also note that criterion 11 is apparently an exception to criterion 10, but this is not
altogether clear since 10 is for fault protection while 11 is for overload protection. Please
rewrite this (these) criterion (criteria) to clarify the SDT’s intent(s).
3. We thank the SDT for addressing our concern regarding radially operated circuits. We
January 24, 2011

note, however, that the key word “operated” from the consideration of comments was
dropped before it reached the standard. Please change the last bullet of B4 to: Radially
operated circuits serving only load are excluded.

Response: Thank you for your comments.
1. The drafting team has clarified this requirement by making it a separate part of criterion 10 and by indicating this criterion applies to load responsive
transformer fault protective relays, if used. A footnote has been added to criterion 10 to clarify this requirement is based on the “dotted line” in IEEE
C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team notes that 150
percent of a typical maximum transformer nameplate rating is on the order of 250 percent (150 percent x 1.67) of the base nameplate rating. The
vertical portion of the mechanical withstand curve is defined by 1/(2xZt), which for a transformer with 12 percent impedance is approximately 400
percent of the nameplate base rating, allowing protection to be set above the loadability requirement in criterion 10 and below the transformer
mechanical withstand curve
2. Criterion 10 and Criterion 11 are meant to address separate applications. Criterion 10 addresses fault protection relays and their response to load;
Criterion 11 explicitly addresses thermal overload protection.
3. The drafting team agrees with your comment and has modified criterion B4 accordingly.
Timothy Beyrle

City of New Smyrna 4
Beach Utilities
Commission
Response: Thank you for your comments.

Affirmative

• R1 and R2 have binary VSLs where they should be percentages of all relays that need
to meet the standard based on statistical sampling.

The VSLs defined are consistent with the VSLs already approved by FERC in PRC-023-1.
Chang G Choi
City of Tacoma,
1
Negative
1. Transmission or Transformers that normally would not be considered BES assets are
Department of
subject to inclusion by the Planning Coordinator. The criteria for inclusion have not been
Public Utilities,
developed yet.
Light Division, dba
Tacoma Power

January 24, 2011

Max Emrick

City of Tacoma,
Department of
Public Utilities,
Light Division, dba
Tacoma Power

2. Attachment A Section 1.6 was added due to FERC Order 733, but it is still vague what
includes “Supervisory Elements”. Please clarify supervisory elements (Does it include
RTUs?)
3. Detailed direction about relay setting methodology could be expanded to 110-kV level
by this revision. Much more research should be devoted to such detailed changes to
evaluate impact to other protection and operation constraints, before such settings are
mandatory.
4. The new requirement (R2) may present conflicting choices for a relay engineer, since
out-of-step blocking is technically challenging to set, sense and discriminate from certain
loading and fault conditions.

Response: Thank you for your comments.
1. The NERC Statement of Compliance Registry Criteria permits application of NERC Reliability Standards to certain facilities operated below 100 kV, such
as for transmission elements operated below 100 kV that are included on a critical facilities list defined by the Regional Entity. The test by which the
Regional Entity may make this determination is outside the scope of this standard. The criteria by which the Planning Coordinators determine for which
of the circuits on the list the applicable entities must comply with the standard are defined in Attachment B.
2. Attachment A, Section 1.6 has been modified to include supervisory elements only as they apply to current-based, communication-assisted schemes
where the scheme is capable of tripping for loss of communications. The drafting team believes this modification provides clarity that this section does
not apply to RTUs and other applications.
3. The drafting team understands your concern and will place this item in the issues database for future consideration in the next general revision of the
standard. However, the drafting team notes that PRC-023-1 already applies to lines operated at 100 kV to 200 kV and the drafting team does not
believe that a significant number of sub-100 kV circuits will be impacted. As such, the drafting team disagrees that more research is required prior to
implementing PRC-023-2.
4. The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners, and Distribution Providers; it
only explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, Section 2 of PRC-023-1.
Randall
City of Vero Beach
1
Affirmative
R1 and R2 have binary VSLs where they should be percentages of all relays that need to meet
McCamish
the standard based on statistical sampling.
Response: Thank you for your comments.
The VSLs defined are consistent with the VSLs already approved by FERC in PRC-023-1.
Michelle A
Cleco Corporation
3
Negative
Cleco respectfully disagrees with NERC by establishing a Standard which mandates how we
Corley
should set protective relays. It is our intention to establish relay settings which safely protect the
public and facilities. If prudent engineering practice results in a relay becoming the limiting
Stephanie
Cleco Power
5
element within a facility, the facility rating should be adjusted as is specified in FAC-008. Relays
Huffman
should not be treated any different than other elements when rating a facility. If system studies
Danny
Cleco Power LLC
1
show the facility is overloaded, then the utility can decide how best to increase the rating.
McDaniel
January 24, 2011

Robert Hirchak

Cleco Power LLC

Response: Thank you for your response.
Your comment is largely related to the existing approved PRC-023-1; this standard results from observations wherein protective relay loadability was heavily
complicit with the 2003 blackout and numerous other major system disturbances, resulting in an acknowledged need to define appropriate criteria.
Paul Morland

Colorado Springs
Utilities

Negative

CSU provides the following comment: The documentation for PRC-023 seems to rely quite
heavily on the usage of spread sheets and and calculations (with the possibility of having bad
formulas). Some engineers who rely on graphical methods from coordination software may be
less likely to have "bad formula" issues. There seems to be a bias in this standard to the formula
based spreadsheet, where there is no mention of guidelines for those spreadsheets or a NERC
provided spreadsheet.

Response: Thank you for your comment.
It is left to each entity to determine how to implement the standard and document compliance. The Measures in the standard are only examples of the types of
documentation that may be considered acceptable evidence.
Donald E.
Commonwealth of
9
Abstain
Criteria 10 under requirement 1 needs to be clarified so that the full implication is completely
Nelson
Massachusetts
understood.
Department of
Public Utilities
Response: Thank you for your comments.
The text of the standard has been modified to clarify the intent of criterion 10. Specifically, a footnote has been added to criterion 10 to clarify that use of the
phrase “mechanical withstand” is based on the “dotted line” in IEEE C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current
Duration, Clause 4.4, Figure 4. The requirement for fault protection has been moved to a separate part of criterion 10 to clarify it applies only to load responsive
transformer fault protection relays, and only when such relays are used.
Christopher L
Consolidated
1
Negative
1. R1 - Clarification is needed on whether criterion 10 requires a transformer to have
de Graffenried Edison Co. of New
load responsive protection to protect from mechanical damage. The wording in criterion
York
10 should be changed to “set transformer fault protection relay or transmission line relay
Peter T Yost

Consolidated
Edison Co. of New
York

Wilket (Jack)
Ng

Consolidated
Edison Co. of New
York

January 24, 2011

on transmission line terminated with only a transformer.” Is this criterion requiring that a
transformer with only differential protection and no other load responsive remote
protection be mitigated with additional load responsive protection? The loading on phase
angle regulators, and series reactors should also be considered and mentioned.
2. Also, there appears to be words missing in criterion 9 of R1: “the maximum current
flow from the ? to the ? under any system configuration.”

Nickesha P
Carrol

Consolidated
Edison Co. of New
York

3. R2 - What is the expectation for verifying that the out-of-step (OOS) blocking
elements allow tripping of phase protection relays for faults that occur during the loading
conditions used to verify transmission line relay loadability? It would be costly and time
consuming to verify this. To comply with this requirement, utilities may have to remove
OOS protections all together.
4. Attachment B - Why does B3 only apply to Nuclear Power Plants only?

Response: Thank you for your comments.
1. The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that
the protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
2. The text has been corrected.
3. The drafting team believes that this requirement will be met by a planning analysis of the settings. This is not a new requirement. PRC-023-1 requires
that this analysis be done within Attachment A.
4. This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes
the added reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
David Frank
Consumers Energy
4
Negative
We have the following comment on the revisions, specifically sub-requirement R1.12a, which
Ronk
states, "Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.". We have no issue with this requirement on transmission lines that are 200 kV or
greater. However, we do have a concern with applying requirement R1.12a on lower voltage
lines now that the Transmission Relay Loadability Standard is being revised to included selected
James B Lewis Consumers Energy
5
equipment 200 kV and below. The positive-sequence line angle on lower voltage lines, such as
69 kV or 46 kV, is significantly lower than 90 degrees. The positive-sequence line angle for 3/0
ACSR, for example, is only 55 degrees. Setting a 90 degree MTA on these lines would require a
much larger reach setting to provide adequate line protection. In some cases, especially for lines
with long spurs and poor line conductor, the increased reach setting may actually provide less
loadability than a reach setting based on an MTA set at the positive-sequence line angle. A 90
degree MTA also dramatically reduces the resistive fault coverage for these lines. For these
reasons, we would propose a modification to sub-requirement R1.12a as follows: Set the
maximum torque angle (MTA) to 90 degrees or the highest supported by the manufacturer on
200 kV or greater transmission lines. Set the maximum torque angle (MTA) to the positivesequence line angle on transmission lines less than 200 kV.
Response: Thank you for your comments.
The drafting team understands your concern and will place this item in the issues database for future consideration in the next general revision of the standard.

January 24, 2011

Russell A
Noble

Cowlitz County PUD

Rick Syring

Cowlitz County PUD

Bob Essex

Cowlitz County PUD

Negative

1. The comment group that Cowlitz PUD coordinated comments with finds R1.10 very
confusing when attempting to understand it in the context of IEEE C57.109-1993.
C57.109 identifies a solid curve as the thermal damage curve, while a dotted dog leg is
the mechanical damage curve. Generally the dog leg is only considered for those class II
and III transformers subjected to frequent through faults and all class IV transformers. Is
the intent of the SDT to require this level of protection for all transformers regardless of
through fault frequency and/or transformer class? If the SDT really meant to protect
transformers from thermal or combination damage, please note that it is not possible to
completely protect transformers from the thermal damage of low current long duration
faults while still complying with the 150% of maximum rating. The thermal damage
curve extends down to twice the base current. A footnote in C57.109 states that base
current is established from the lowest nameplate kVA rating. A typical transformer with
two stages of cooling will have a high nameplate rating of 1.67 times this base rating.
The first bullet of R1.10 states affected entities must allow 1.5 times the maximum, so
we are up to 2.5 times the base rating. Since we must allow this much without tripping,
the relay must be set even higher. 1.2 times would be a secure margin, so the relay is set
to pickup at 3 times the base rating. This setting would of course violate the first part of
R1 criterion 10 because the transformer’s fault capability would be exceeded for faults
between 2 and 3 times the base rating.
2. We also note that criterion 11 is apparently an exception to criterion 10, but this is not
altogether clear since 10 is for fault protection while 11 is for overload protection. Please
rewrite this (these) criterion (criteria) to clarify the SDT’s intent(s).
3. We thank the SDT for addressing our concern regarding radially operated circuits. We
note, however, that the key word “operated” from the consideration of comments was
dropped before it reached the standard. Please change the last bullet of B4 to: Radially
operated circuits serving only load are excluded.

Response: Thank you for your comments.
1. The drafting team has clarified this requirement by making it a separate part of criterion 10 and by indicating this criterion applies to load responsive
transformer fault protective relays, if used. A footnote has been added to criterion 10 to clarify this requirement is based on the “dotted line” in IEEE
C57.109-1993 – IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4. The drafting team notes that 150
percent of a typical maximum transformer nameplate rating is on the order of 250 percent (150 percent x 1.67) of the base nameplate rating. The
vertical portion of the mechanical withstand curve is defined by 1/(2xZt), which for a transformer with 12 percent impedance is approximately 400 percent
of the nameplate base rating, allowing protection to be set above the loadability requirement in criterion 10 and below the transformer mechanical
January 24, 2011

withstand curve.
2. Criterion 10 and Criterion 11 are meant to address separate applications. Criterion 10 addresses fault protection relays and their response to load;
Criterion 11 explicitly addresses thermal overload protection.
3. The drafting team agrees with your comment and has modified criterion B4 accordingly.
Michael F
Dominion
3
Gildea
Resources Services
Response: Thank you for your comments.

Affirmative

5.1 Requirement R1. Dominion would like to see the exception of "switch on to fault" schemes
added back in.

The drafting team understands the commenter’s concern that the proposed implementation plan for PRC-023-2 had the unintended consequence of shortening
the time provided for Facility owners to comply with Requirement R1 for switch-on-to-fault schemes. The drafting team has modified the effective dates in the
standard to address this problem.
Henry Ernst-Jr Duke Energy
3
Negative
Duke Energy appreciates the work of the drafting team, but believes additional changes
Carolina
are needed before voting to approve PRC-023-2.

1. R6.1 and R6.2 unnecessarily duplicate the first part of Attachment B, and should be
deleted from R6.
2. R6.3 and R6.4 are both associated with maintaining the list and should be combined
into a separate requirement (new R7), with its own VRF and VSLs. Including the year
for a facility should apply to all the criteria, not just B4. Suggested wording for new R7:
“Maintain a list of circuits that must comply with this standard due to meeting
Attachment B criteria. For each circuit, include the applicable criteria and the year
studied for which the criteria first applies, when a facility is added to the list.”
3. R6.5 should become a new R8 with its own VRF and VSLs. No wording changes
needed.
4. Since the Attachment B criteria are applied beyond the operating horizon, R7 should
be rewritten (and also renumbered as R9). Suggested wording: “ Each Transmission
Owner, Generator Owner, and Distribution Provider shall implement Requirement R1,
Requirement R2, Requirement R3, Requirement R4, and Requirement R5 for each
facility that is added to the Planning Coordinator’s list of facilities that must comply with
this standard pursuant to Requirement R6, by the first day of the first calendar quarter of
the year in which Attachment B criteria first apply. [Violation Risk Factor: High] [Time
Horizon: Long Term Planning]
January 24, 2011

5. B2 needs additional clarification, because identification could be in the short term or
long term planning horizon. Suggested rewording: “B2. Each circuit that is a monitored
Element of an IROL where the IROL was determined beyond the operating horizon.”
6. B3 needs additional clarification, to explicitly identify the necessary agreement
between the plant owner and Transmission Entity. Suggested rewording: “Each circuit
that forms a path (as agreed to by the plant owner and the Transmission Entity pursuant
to NUC-001) to supply off-site power to nuclear plants.
Response: Thank you for your comments.
1. R6.1 and R6.2 have been removed from PRC-023-2 in response to comments.
2. The drafting team believes that it is appropriate to include details regarding maintenance of the list as a part of Requirement R6 consistent with the
existing standard PRC-023-1. While the drafting team disagrees that parts 6.3 and 6.4 should become a separate requirement, the drafting team has
combined these into one part of Requirement R6 consistent with the commenter’s recommendation. The combined text, now part 6.1, reads:
“6.1
Maintain a list of circuits operated below 200kV and subject to the standard per application of Attachment B, which includes the first calendar
year in which any criterion in Attachment B applies.”
3. The structure of the standard text within R6 including the approved VRFs and VSLs is similar to R3 in PRC-023-1, and therefore it is beyond the scope of
the project to modify this structure.
4. The drafting team notes that Requirement R7 has been deleted in response to other comments. The Effective Dates section has been modified to
address the timeframe in which Facility owners must comply with Requirements R1 through R5 when the Planning Coordinator identifies a circuit for
which the Facility owner must comply with the standard.
5. In response to several comments on this subject, the drafting team has replaced the reference to “determined in the long-term planning horizon” with
“determined in the planning horizon pursuant to FAC-010.”
6. In response to comments on criterion B3 the drafting team has modified the criterion to refer explicitly to “the Nuclear Plant Interface Requirements
(NPIRs) pursuant to NUC-001.”
Chuck B
Electric Reliability
2
Negative
ERCOT ISO has filed comments through the online form. Please reference filed comments for
Manning
Council of Texas,
details.
Inc.
Response: Thank you for your comments.
Please refer to the drafting team responses in the Consideration of Comments document.
Robert
FirstEnergy Energy
1
Negative
Please see FirstEnergy's comments submitted separately through the comment period posting.
Martinko
Delivery
Kevin Querry
FirstEnergy
3
Solutions
Mark S
FirstEnergy
6
Travaglianti
Solutions
January 24, 2011

Response: Thank you for your comments.
Please refer to the drafting team responses in the Consideration of Comments document.
Frank Gaffney
Florida Municipal
4
Affirmative
R1 and R2 have binary VSLs where they should be percentages of all relays that need to meet
Power Agency
the standard based on statistical sampling.
David
Florida Municipal
5
Schumann
Power Agency
Richard L.
Florida Municipal
6
Montgomery
Power Agency
Thomas W.
Fort Pierce Utilities
4
Richards
Authority
Response: Thank you for your comments.
The VSLs defined are consistent with the VSLs already approved by FERC in PRC-023-1.
Ajay Garg
Hydro One
1
Negative
Hydro One is casting a negative vote with the following comments:
Networks, Inc.
David L Kiguel

Hydro One
Networks, Inc.

PRC-023-2 addresses the Phase I directives from FERC Order 733 including a process
for use in determining which facilities (transmission lines operated below 200 kV and
transformers with low voltage terminals connected below 200 kV) must meet specific
relay loadability criteria. Category B4 in the criteria is intended to identify 100 kV to
200 kV lines that will experience different degrees of thermal overload with respect to
their Facility Rating for different loading duration. Since these durations may be as long
as several hours, it is unreasonable to impose the restriction of “without manual system
adjustment in between (the two contingencies)” on the B4 test procedure. Aside from
this restriction, the degree of thermal overload with respect to Facility Rating (of various
loading durations) is not a relevant measure of the significance of that overload for the
reliability of the system. The correct measure is whether tripping of the overloaded line,
either by manual operator action (along with other system adjustments that would be
available during the relevant time period) or as a consequence of protection and control
actions, would result in cascaded tripping of other bulk transmission lines.

Response: Thank you for your comments.
Circuits subject to loading in excess of their emergency rating are susceptible to tripping, which could lead to instability, uncontrolled separation, or cascading
outages. The drafting team believes it is impractical to expect the Planning Coordinator to anticipate and assess every possible system situation that could lead
to these conditions. Thus the criteria in Attachment B were selected to identify circuits that present a risk of cascading outages if relay loadability requirements
are not met. The drafting team has added to some of the criteria that the Planning Coordinator is to consult with the Facility owner when performing its
assessment to provide the Facility owner an opportunity for input into the assessment. Additionally, an appeals process will be included in the NERC Rules of
Procedure so that a Facility owner may appeal a decision in the event it believes a circuit is incorrectly identified by the Planning Coordinator.

January 24, 2011

Kim Warren

Independent
Electricity System
Operator

Negative

Clarification is needed on whether criterion 10 requires a transformer to have load
responsive protection to protect from mechanical damage. The wording in criterion 10
should be changed to “set transformer fault protection relay or transmission line relay on
transmission line terminated with only a transformer.” Is this criteria requiring that a
transformer with only differential protection and no other load responsive remote
protection be mitigated with additional load responsive protection?

Response: Thank you for your comments.
The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
Michael
International
1
Negative
ITC votes "Negative" on this ballot for the following reasons:
Moltane
Transmission
Company Holdings
R2: ITC is not clear that we can provide the documentation required to provide evidence
Corp

that an OSB element will, with heavy load, allow tripping. Out of step relaying is based
on a moving impedance locus for a swing versus a fault. Different relays will operate
differently and in some relays there is a small period of time, 2 seconds, where heavy
loads will block tripping. Is the requirement trying to say that the out of step blocking
element must never pick up and block for unusually heavy loads or is there more to it?
This requirement is too restrictive and does not allow for engineering judgment for out
of step protection. The drafting team must provide guidance on how to meet this
requirement? We are concerned that an unusually heavy load swing will appear to the
correct OSB setting as a swing and prevent tripping for a short time. Setting OSB relays
per the new R2 to allow tripping for these severe and highly improbable conditions may
remove blocking for the actual predicted swings and have a worse effect on the BES.

R7: When this new criteria goes into effect, circuits will become designated as “Critical”
that were not before. There must be adequate time allowed for utilities to budget,
engineer and construct new relay systems to meet this standard. Some medium voltage
lines may need to be re-terminated and will require a significant amount of time to get
planned and constructed. We suggest an implementation time of 36 months after
identification by the planning coordinator.
Response: Thank you for your comment.
R2: The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners, and Distribution Providers; it only
explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, Section 2 of PRC-023-1.
R7: The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation time frame to 39
months to provide the Facility owners time to budget, procure, and install any protection system equipment modifications and for consistency with PRC-023-1.
January 24, 2011

Kathleen
Goodman

ISO New England,
Inc.

Negative

ISO New England is voting no for the following reasons:
B2. Item B2 adds significant confusion to the process. The long term planning horizon
may include transmission projects which have not even been built or alternative system
configurations which do not exist, making it impossible for affected parties to set their
relays appropriately. Suggested replacement language to avoid this issue: “Each circuit
that is a monitored element of an IROL, assuming that all transmission elements are in
service and the system is under normal conditions.”
B3. This item indicates that the circuits to be considered are to be agreed to by the plant
owner and the Transmission Entity. Attachment B is applicable to the Planning
Coordinator. If this item is by agreement by the plant and the Transmission Entity it
should be removed from Attachment B and placed elsewhere in the document. If this is
intended to apply to the Planning Coordinator, Transmission Entity should be replaced
with Planning Coordinator. Why does B3 only apply to Nuclear Power Plants?
B4. This criterion is overly stringent and should be deleted. The system is neither
planned nor operated to allow for two overlapping outages without operator action in
between. If this criterion is retained, it should be made consistent with the requirements
of TPL-003 where operator actions can be assumed between the first and second
contingencies. Since a similar comment was made previously, more information is being
provided following. 1. Since the system is neither planned nor operated to two
overlapping outages in between, such testing may result in unsolved cases, or voltages
well below criteria. In the case of an unsolved case, there are no flows to evaluate,
making this standard impossible to apply. In the case of a solved case with voltages well
below criteria, currents are likely to be incredibly high and therefore viewed as
unrealistic. These concerns may limit the contingency selection to those which are not
severe, eliminating any perceived benefit from this testing. 2. There is no guidance
provided on how the system should be dispatched in the model upon which the
overlapping contingencies are tested. This will result in significant discrepancies
between the base assumptions used by the various Planning Coordinators. The contents
of this standard should be reviewed to reflect the new definition of the Bulk Electric
System.

Response: Thank you for your comments.
January 24, 2011

B2: In response to several comments on this subject the drafting team has replaced the reference to “determined in the long-term planning horizon” with
“determined in the planning horizon pursuant to FAC-010.”
B3: This criterion applies to the Planning Coordinator and requires that the Planning Coordinator include circuits that form a path “(as agreed to by the plant
owner and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs) pursuant to
NUC-001” on the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes the
added reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
B4: The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard, rather, it is to be used as a screen to
determine whether the relay loadability settings are properly set such that the circuits will not be tripped prematurely, resulting in widening of the initiating
outage. As such, B4 does not require that all double contingency combinations be tested. It also does not require that the loadings respect the published
applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to be studied without manual
system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay settings on the lines remaining in
service would not inappropriately trip the lines. This standard, like all others, will need to be reviewed when a new definition of the Bulk Electric System is
approved.
Michael
Kansas City Power
1
Negative
Attachment B is duplicative to the criteria established in the TPL planning standards and can be
Gammon
& Light Co.
conflicting regarding the identification of critical circuits by Planning Authorities and Transmission
Planners. Removal of Attachment B is recommended and replace with language that specifies
Charles Locke
Kansas City Power
3
facilities 100kv and above identified by Planning Authority or by the Transmission Planner are
& Light Co.
applicable to the Standard.
Jessica L
Klinghoffer

Kansas City Power
& Light Co.

Response: Thank you for your comments.
Attachment B is not duplicative of the criteria established in the TPL planning standards, nor does it conflict with any responsibilities of Planning Coordinators
(formerly Planning Authorities) or Transmission Planners. The purpose of the criteria in Attachment B is not to assess whether the system performance meets
the TPL standard; rather, it is to be used as a screen to determine whether relays must be set to meet loadability requirements such that the circuits will not be
tripped prematurely, resulting in widening of the initiating outage. The introductory sentence in Attachment B has been revised to clarify the implication of
identifying circuits per all criteria in the attachment: “If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for
that circuit.” These criteria provide a consistent methodology for Planning Coordinators to perform the determination presently assigned in Requirement R3 of
PRC-023-1 (now Requirement R6 in PRC-023-2). This requirement supports the reliability purpose of this standard by identifying the circuits below 200 kV
which could lead to cascading outages, if Protection Systems are not set according to the relay loadability requirements.
Stan T. Rzad
Walt Gill

Keys Energy
Services
Lake Worth Utilities

January 24, 2011

Affirmative

R1 and R2 have binary VSLs where they should be percentages of all relays that need to meet
the standard based on statistical sampling. But that doesn't seem to be that big a deal

1
21

Response: Thank you for your comments.
The VSLs defined are consistent with the VSLs already approved by FERC in PRC-023-1.
Joe D Petaski
Manitoba Hydro
1
Negative
Please see comments submitted by Manitoba Hydro in the formal comment period.
Greg C. Parent

Manitoba Hydro

S N Fernando

Manitoba Hydro

Daniel Prowse

Manitoba Hydro

Response: Thank you for your comments.
Please refer to the drafting team responses in the Consideration of Comments document.
Terry Harbour
MidAmerican
1
Negative
1) The Attachment B criteria for determining what circuits must follow PRC-023
Energy Co.
according to FERC Order 733 and paragraph 69 specifying tests to determine

what facilities are “critical” to BES reliability are wrong and go beyond the
FERC directive. There is no technical basis for including flowgates as an
appropriate measure of an item that is critical to reliability. A flowgate is a point
of market congestion that may or may not have an important reliability impact.
Because a “flowgate” may not have a reliability impact any larger than any other
transmission line, Appendix B criterion B1 should be dropped. If the standard
drafting team wishes to keep criteria B1 it should prove there is a sound and
measureable method to show a flowgate is critical to the operation of the BES
and the loss of such a facility would result in instability, uncontrolled separation,
and cascading.
2)

References to Planning Coordinators and Regional Entities in sections 4.2.2,
4.2.3, 4.2.6, R6, and Attachment B should be eliminated or replaced with
Transmission Owner and Transmission Operators. Transmission Owners and
Operators understand what facilities are critical to the operation of the BES and
should determine what is and is not critical to the BES based upon FPA Section
215 criteria, IROLs, and TPL standards.

Response: Thank you for your comments.
1) Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address
reliability concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could
lead to instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due
to transactions. While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability. The
Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to
instability, uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as
January 24, 2011

applicable circuits under PRC-023-2. The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC;
however, the NERC Functional Model does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year
and beyond) with Transmission Planners, Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and
neighboring Planning Coordinators. Thus it is appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to
whether the monitored Facilities of a flowgate are added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution
Providers must comply with PRC-023-2. Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates
and has replaced the reference to “long-term reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this
more clearly reflects the intent to exclude flowgates that are established on a temporary basis and more clearly identifies the role of the Planning
Coordinator in applying criterion B1.
2) The Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform the assessment in
Attachment B. The drafting team also notes that assigning this responsibility to the Planning Coordinator is consistent with the approved PRC-023-1
and FERC Order No. 733.
Thomas C.
MidAmerican
3
Negative
1) The Attachment B criteria for determining what circuits must follow PRC-023
Mielnik
Energy Co.
criteria according to the FERC Order 733 and paragraph 69 specifying tests to

determine what facilities are “critical” to BES reliability is wrong and goes
beyond the FERC directive. There is no technical basis for including flowgates as
an appropriate measure of an item that is critical to reliability. A flowgate is a
point of market congestion that may or may not have a important reliability
impact. Because a “flowgate” may not have a reliability impact any larger than
any other transmission line, Appendix B criterion B1 should be dropped. If the
standard drafting team wishes to keep criteria B1 it should prove that there is a
sound and measureable method to prove that a flowgate is critical to the
operation of the BES and the loss of such a facility would result in instability,
uncontrolled separation, and cascading.
2)

References to Planning Coordinators and Regional Entities in sections 4.2.2,
4.2.3, 4.2.6, R6, and Attachment B should be eliminated or replaced with
Transmission Owner and Transmission Operators. These entities understand
what facilities are critical to the operation of the BES and should determine what
is and is not critical to the BES based upon FPA Section 215 criteria, IROLs, and
TPL standards.

to transactions. While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability. The
Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to
instability, uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as
applicable circuits under PRC-023-2. The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC;
however, the NERC Functional Model does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year
and beyond) with Transmission Planners, Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and
neighboring Planning Coordinators. Thus it is appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to
whether the monitored Facilities of a flowgate are added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution
Providers must comply with PRC-023-2. Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates
and has replaced the reference to “long-term reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this
more clearly reflects the intent to exclude flowgates that are established on a temporary basis and more clearly identifies the role of the Planning
Coordinator in applying criterion B1.
2) The Planning Coordinator is the NERC Functional Model entity with the wide-area view and study expertise necessary to perform the assessment in
Attachment B. The drafting team also notes that assigning this responsibility to the Planning Coordinator is consistent with the approved PRC-023-1
and FERC Order No. 733.
Christopher
Schneider

MidAmerican
Energy Co.

Response: Thank you for your comments.

Negative

1) The Attachment B criteria for determining what circuits must follow PRC-023 criteria
according to the FERC Order 733 and paragraph 69 specifying tests to determine what
facilities are “critical” to BES reliability is wrong and goes beyond the FERC directive.
There is no technical basis for including flowgates as an appropriate measure of an item
that is critical to reliability. A flowgate is a point of market congestion that may or may
not have a important reliability impact. Because a “flowgate” may not have a reliability
impact any larger than any other transmission line, Appendix B criterion B1 should be
dropped. If the standard drafting team wishes to keep criteria B1 it should prove that
there is a sound and measureable method to prove that a flowgate is critical to the
operation of the BES and the loss of such a facility would result in instability,
uncontrolled separation, and cascading.
2) References to Planning Coordinators and Regional Entities in sections 4.2.2, 4.2.3, 4.2.6,
R6, and Attachment B should be eliminated or replaced with Transmission Owner and
Transmission Operators. These entities understand what facilities are critical to the
operation of the BES and should determine what is and is not critical to the BES based
upon FPA Section 215 criteria, IROLs, and TPL standards.

1) Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address
reliability concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could
lead to instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due
January 24, 2011

flowgates. NERC’s definition of flowgate includes two components. Let’s focus on the
first component which represents those flowgates defined in the IDC. Because IDC
flowgates list is updated monthly and the IDC users can add temporary flowgates to the
IDC at any time, this is an inappropriate list to use. We appreciate the drafting team’s
attempt to resolve this issue by including the caveat “that has been included to address
long-term reliability concerns, as confirmed by the applicable Planning Coordinator.”
However, this really only confuses the matter and does not solve it. Reliability
Coordinators add flowgates to manage real-time congestion. Planning Coordinators do
not. Per the NERC functional model, they do not even have a role in deciding which
flowgates to add to the IDC. Flowgates are added to the IDC to mitigate existing, known
congestion points not congestion points identified in a long-term planning study that may
never materialize due to changing conditions. Thus, IDC flowgates should be
specifically excluded. Now let us focus on the second component of flowgate. The
second component is much like the first component in that is it a mathematical construct
to analyze the impact of power flows on the BES except is not required to be included in
the IDC. There is nothing in the definition of a flowgate to give credence that is
represents anything more than point to calculate power flows and the impact of
transactions. Flowgates are primarily used to manage congestion on the system and to
January 24, 2011

sell transmission system. Because it is convenient to select a group of lines as a proxy to
sell transmission service or manage congestion does not mean that those group of lines
represent a reliability issue. Thus, we do not believe any flowgates should be included in
the list. Any true reliability issues can be identified through the TPL studies and those
facilities that do not meet the performance requirements are what should be used.
2. We do not support criterion B4. It exceeds what is required in the TPL standards and
what is required per the reliability directive in Order 729. The TPL standards allow
system operator intervention for category C3 contingencies between the two independent
Category B contingencies. This standard should not exceed those requirements in the
TPL standards. Paragraphs 79 and 80 of FERC Order 729 contain the relevant directives
regarding the Planning Coordinator test. Paragraph 79 states that the test “must include
or be consistent with the system simulations and assessments that are required by the
TPL Reliability Standards and meet the system performance levels for all Category of
Contingencies used in transmission planning.” Paragraph 80 states that “the test must be
consistent with the general reliability principles embedded in the existing series of TPL”
standards. Thus, exceeding the TPL standards could be argued as deviating from the
directive. In response to comments that did not support this criterion during the first
posting, the standards drafting team responded with “Testing multiple element
contingencies while accounting for system adjustments between each element outage
will not yield any facilities to be subject to PRC-023 as long as TPL-003 system
performance requirements are met.” We think the drafting team missed a basic point
about the standard. The issue is not whether the registered entity develops and
documents corrective action plans TPL-003-0a R2 and R3. The issue is if the system as
currently designed meets the performance requirements in TPL-003-0a R1 which allows
for operator interventions on Category C3 contingencies. For those C3 contingencies that
don’t currently meet the performance obligations after operator interventions, the subject
facilities would be included PRC-023-2 R6 list of facilities.
3. We do not believe this requirement R4 is needed. Limiting a relay setting to 115% of
the associated transmission line’s highest seasonal 15 minute rating does not equate to a
line that will trip before the operator has time to intervene. It does not mean the line will
trip in 15 minutes. In fact, the operator should be taking action well in advance of
reaching a 15 minute limit and the operator is likely only using the 15 minute rating in
extreme circumstances.
January 24, 2011

4. Furthermore, PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and FAC-009-1.
FAC-008-1 and FAC-009-1 already collectively require the Transmission Owner and
Generator Owner to establish a facilities ratings methodology, rate its facilities
consistent with its methodology and to communicate those ratings and methodology to
its Planning Coordinator, Reliability Coordinator and Transmission Operator. More
specifically FAC-008-1 R1.2.1 requires the Transmission Owner and Generator Owner
to consider relay protective devices in its ratings methodology and FAC-009-1 R2
requires the communication of the ratings including those limited by relays. As a result,
neither PRC-023-2 R3 nor R4 is even needed. We assume the drafting team must be
aware of these FAC standard requirements because they did not even require reporting to
the Reliability Coordinator, Planning Coordinator and Transmission Operator of those
circuits that are actually limited by the relay per criterion 12. We agree that FAC-008-1
and FAC-009-1 collectively establish the necessary requirements to compel the
Transmission Owner and Generator Owner to communicate these relay limited circuits
and that no additional requirements are necessary.
Response: Thank you for your comments.
1. Congestion and system reliability are not mutually exclusive concerns. The Interchange Distribution Calculator (IDC) was developed to address
reliability concerns. Markets are constrained to ensure that the transmission system is operated within physical system constraints that if violated, could
lead to instability, uncontrolled separation, or cascading. The IDC is intended to identify and unload critical circuits that could become overloaded due
to transactions. While Flowgates and the IDC are used to manage congestion, the underlying basis for doing so is to preserve system reliability. The
Flowgate Methodology defines that Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits. If monitored
Facilities of flowgates do not meet the Relay Loadability requirements in PRC-023, violation of physical system limitations could occur, leading to
instability, uncontrolled separation, or cascading outages. As such, it is appropriate and necessary to include monitored Facilities of flowgates as
applicable circuits under PRC-023-2. The drafting team acknowledges that Planning Coordinators do not decide which flowgates are included in the IDC;
however, the NERC Functional Model does indicate that Planning Coordinators are responsible for coordinating transfer capability (generally one year
and beyond) with Transmission Planners, Reliability Coordinator, Transmission Owner, Transmission Operator, Transmission Service Provider, and
neighboring Planning Coordinators. Thus it is appropriate that Planning Coordinators, in applying the criteria in Appendix B, provide a screening as to
whether the monitored Facilities of a flowgate are added to the list of circuits for which Transmission Owners, Generator Owners, and Distribution
Providers must comply with PRC-023-2. Based on a number of comments, the drafting team has modified criterion B1 to refer to “permanent” flowgates
and has replaced the reference to “long-term reliability concerns” with “reliability concerns for loading of that circuit.” The drafting team believes this
more clearly reflects the intent to exclude flowgates that are established on a temporary basis and more clearly identifies the role of the Planning
Coordinator in applying criterion B1. FERC Order 733 has directed that this requirement be explicitly addressed within the requirements of PRC-023-2.
FAC-008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the
relay loadability is based on a 15-minute rating.
2. The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a
January 24, 2011

screen to determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in
widening of the initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require
that the loadings respect the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain
combinations of line outages to be studied without manual system adjustment to ensure that, if the manual adjustments were not completed before the
second contingency, the relay settings on the lines remaining in service would not inappropriately trip the lines.
3. Providing this information to the specified entities addresses the potential for confusion as to the amount of time available to take corrective action.
4. FAC-008 and FAC-009 do not address this issue. FAC-009 requires transmitting the Facility Rating, whereas PRC-023-2 requires notification when the
relay loadability is based on a 15-minute rating.
Richard Burt
Minnkota Power
1
Negative
See comments submitted by MRO NSRS.
Coop. Inc.
Response: Thank you for your comments.
Please see the responses to comments submitted by MRO NSRS.
Saurabh
Saksena

National Grid

Negative

1. As per Section 4.2.3 (also included as bullet point 2 of Applicable circuits in
Attachment B) "Transmission Lines operated below 100 kV that Regional Entities have
identified as critical facilities for the purposes of the Compliance Registry and the
Planning Coordinator has determined are required to comply with this standard."
National Grid believes that voltage levels less than 100 kV are outside NERC's
jurisdiction and hence, requirements related to sub 100 kV levels should not be part of
NERC standards.
2. National Grid recommends a provision in the standard which allows entities an option
to 1. Either comply with standard for all applicable elements or 2. Apply the
methodology as stated in Attachment B. The rationale is that entities that choose to
comply with PRC-023 for all applicable elements should be recognized and should be
exempted from complying with the methodology in Attachment B.
3. Requirement R6 of the proposed standard requires entities to apply criteria in
Attachment B and conduct assessments with no more than 15 months between
assessments to determine which transmission elements must comply with this standard.
TPL standard which is considered to be the primary standard dealing with designing and
planning of the system allows an interim assessment to rely on previous years
simulations and does not mandate a stringent 15 month period between assessments.
National Grid believes that an auxiliary PRC-023 standard should not present more
stringent requirements than the primary TPL standard and recommends to remove the

January 24, 2011

"15 month between assessments" requirement.
4. National Grid seeks clarification on whether criterion 10 requires transformer to have
load responsive protection to protection from mechanical damage. The wording in
criterion 10 should be changed to “set transformer fault protection relay or transmission
line relay on transmission line terminated with only a transformer.” For example, is this
criteria requiring that a transformer with only differential protection and no other load
responsive remote protection be mitigated with additional load responsive protection?

Response: Thank you for your comments.
1) The drafting team understands the concern with including facilities operated below 100 kV; however, the NERC Statement of Compliance Registry
Criteria does allow Regional Entities the ability to identify such facilities operated below 100 kV as required to comply with NERC Reliability Standards.
The drafting team has replaced the phrase “critical for the purposes of the Compliance Registry” with text from the ¶60 of Order No. 733, which
references text in section III.d.2 of the NERC Statement of Compliance Registry Criteria, so the second category of circuits to be evaluated now refers to
transmission lines and transformers operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team
made corresponding modifications to the Applicability section.
2) The drafting team has added a new criterion B6 to include any circuit mutually agreed upon for inclusion by the Planning Coordinator and the Facility
owner. Any circuit identified by criterion B6 would not require application of the other criteria in Attachment B.
3) The drafting team intended that an assessment be performed each year, but that the power flow analyses used to support the assessment need not be
performed unless material changes to the system have occurred since the last assessment. The drafting team has added a footnote to criterion B4 to
clarify this intent.
4) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that
the protection be set in accordance with Criterion 10 if it does exist. The standard has been modified to clarify this point.
Randy
MacDonald

New Brunswick
1
Negative
Criteria 10 under Requirement 1. The Criteria could subject the industry to adding phase
Power Transmission
overcurrent protection to a large number of transformers. Clarification is needed
Corporation
Alden Briggs
New Brunswick
2
Negative
Criteria 10 under Requirement 1. The Criteria could subject the industry to unnecessarily adding
System Operator
phase overcurrent protection to a large number of transformers. Clarification is required.
Response: Thank you for your comments.
The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
Gregory
New York
2
Negative
comments provided
Campoli
Independent
January 24, 2011

System Operator
Response: Thank you for your comments.
Please refer to the drafting team responses in the Consideration of Comments document.
Gerald
New York Power
5
Negative
Comments to Question 1: ----------------------Mannarino
Authority
1. Clarification is needed on whether criterion

4.
5.

10 requires a transformer to have
load responsive protection to protect from mechanical damage, either from
internal faults, or through faults. If load responsive protection for the transformer
element does not presently exist, i.e. only differential protection exists for the
transformer element, will load responsive transformer protection have to be
added to comply with this criterion?
The wording in criterion 10 should be changed to “Set transformer fault
protection relays or transmission line relays on transmission lines terminated only
with a transformer to …….”
Is this criteria requiring that a transformer with only differential protection and
no other load responsive remote protection be supplemented with additional load
responsive protection?
The loading on phase angle regulators, and series reactors should be considered
and mentioned.
Also, there appears to be words missing in criterion 9 of R1: “the maximum
current flow from the ? to the ? under any system configuration.” From the
NERC Webinar on 11/23/10 the intention was to address the possible locations
where phase protection for the transformer could exist and not imply that this
protection was needed at both locations.

Comments to Question 8: ----------------------6. B2. Item B2 adds significant confusion to the process. The long term planning
horizon may include transmission projects which have not even been built or
alternative system configurations which do not exist, making it impossible for
affected parties to set their relays appropriately. Suggested replacement language
to avoid this issue: “Each circuit that is a monitored element of an IROL,
assuming that all transmission elements are in service and the system is under
normal conditions.”
7. B3. This item indicates that the circuits to be considered are to be agreed to by
the plant owner and the Transmission Entity. Attachment B is applicable to the
Planning Coordinator. If this item is by agreement by the plant and the
January 24, 2011

Transmission Entity it should be removed from Attachment B and placed
elsewhere in the document. If this is intended to apply to the Planning
Coordinator, Transmission Entity should be replaced with Planning Coordinator.
Why does B3 only apply to Nuclear Power Plants?
8. B4. This criterion is overly stringent and should be deleted. The system is neither
planned nor operated to allow for two overlapping outages without operator
action in between. If this criterion is retained, it should be made consistent with
the requirements of TPL-003 where operator actions can be assumed between the
first and second contingencies. Since a similar comment was made previously,
more information is being provided following. 1. Since the system is neither
planned nor operated to two overlapping outages in between, such testing may
result in unsolved cases, or voltages well below criteria. In the case of an
unsolved case, there are no flows to evaluate, making this standard impossible to
apply. In the case of a solved case with voltages well below criteria, currents are
likely to be incredibly high and therefore viewed as unrealistic. These concerns
may limit the contingency selection to those which are not severe, eliminating
any perceived benefit from this testing. 2. There is no guidance provided on how
the system should be dispatched in the model upon which the overlapping
contingencies are tested. This will result in significant discrepancies between the
base assumptions used by the various Planning Coordinators. The contents of this
standard should be reviewed to reflect the new definition of the Bulk Electric
System.
Response: Thank you for your comments.
1) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that
the protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
2) The drafting team has considered this comment and similar comments and has modified the text of the standard as appropriate.
3) The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that
the protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
4) The drafting team believes that the phase angle regulating transformers are already included in the standard in Criteria 10 and 11, and that series
reactors are already included as part of the element in which they are inserted. This comment will be considered as we prepare future versions of the
standard.
5) The text of the standard has been corrected.
6) In response to several comments on this subject the drafting team has replaced the reference to “determined in the long-term planning horizon” with
“determined in the planning horizon pursuant to FAC-010.”
January 24, 2011

7) This criterion applies to the Planning Coordinator and requires that the Planning Coordinator include circuits that form a path “(as agreed to by the plant
owner and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs)
pursuant to NUC-001” on the list of circuits for which Transmission Owners, Generator Owners, and Distribution Providers must comply with PRC-023-2.
This criterion applies specifically to nuclear plants for the purpose of supporting nuclear plant safe operation and shutdown. The drafting team believes
the added reference to the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001 better reflects this intent.
8) The drafting team received several comments regarding “going beyond” TPL requirements by not simulating manual system adjustment in between
contingencies. The purpose of this criterion is not to assess whether the system performance meets the TPL standard; rather, it is to be used as a screen
to determine whether relays must be set to meet loadability requirements such that the circuits will not be tripped prematurely, resulting in widening of the
initiating outage. As such, criterion B4 does not require that all double contingency combinations be tested. It also does not require that the loadings
respect the published applicable ratings of the circuits. It does require that engineering judgment be used to select certain combinations of line outages to
be studied without manual system adjustment to ensure that, if the manual adjustments were not completed before the second contingency, the relay
settings on the lines remaining in service would not inappropriately trip the lines.
Guy V. Zito

Northeast Power
Coordinating
Council, Inc.

Response: Thank you for your comments.

Negative

Question has arisen during a technical evaluation of the NPCC membership regarding Criteria 10
under Requirement 1 of the draft standard. Would this requirement necessitate adding phase
overcurrent protection to all transformers? Clarification is required for this Criteria before NPCC
can support this standard so as to identify the implications of the adoption of such a
requirement.

The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
David H.
Northeast Utilities
1
Negative
Further clarification is needed for criterion 10 in R1.
Boguslawski
1. Is it the intention of this criterion that all applicable transformers must have load

responsive protection to prevent mechanical damage from a through fault? If load
responsive protection for the transformer element does not presently exist, i.e.
only differential protection exists for the transformer element, will load
responsive transformer protection have to be added to comply with this criterion?
2. It is also suggested that R1 Criterion 10 wording be changed to “Set transformer
fault protection relays or transmission line relays on transmission lines
terminated only with a transformer to …….” since it appears from the NERC
Webinar on 11/23/10 that the intention was address the possible locations where
phase protection for the transformer could exist and not infer that this protection
was needed at both locations.
Response: Thank you for your comments.
1. The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that
the protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point.
January 24, 2011

2. The drafting team has considered this comment and similar comments and has modified the text of the standard as appropriate.
Joseph O'Brien

Northern Indiana
6
Public Service Co.
Response: Thank you for your comments.

Negative

See submitted comment form under "Posted for Comment"

Please refer to the drafting team responses in the Consideration of Comments document.
Michelle
Occidental
5
Negative
1. Further clarification is needed for criterion 10 in R1. Is it the intention of this
DAntuono
Chemical
criterion that all applicable transformers must have load responsive protection

to
prevent mechanical damage from a through fault? If load responsive protection
for the transformer element does not presently exist, i.e. only differential
protection exists for the transformer element, will load responsive transformer
protection have to be added to comply with this criterion?
2. It is also suggested that R1 Criterion 10 wording be changed to “Set transformer
fault protection relays or transmission line relays on transmission lines
terminated only with a transformer to …….” since it appears from the NERC
Webinar on 11/23/10 that the intention was address the possible locations where
phase protection for the transformer could exist and not infer that this protection
was needed at both locations.

Negative

Please see FirstEnergy's comments submitted separately through the comment period posting

Please refer to the drafting team responses in the Consideration of Comments document.
Chifong L.
Pacific Gas and
1
Negative
1. R2 is not clear. Is the requirement that OSB elements
Thomas
Electric Company
from tripping for a fault during overloaded conditions?

should not prevent the relay

2. R6 does not include circuits or facilities that may have been deemed critical facilities
for CIP purposes.
3. R7 timeframe to comply is 24 months. We are not sure that this is sufficient time to
January 24, 2011

get a job approved and constructed to replace relays on a terminal if they cannot be set to
comply. Few relays 200kV and above did not meet loadability requirements, but we
suspect there are many more at 100-200kv and below 100kV.
4. There is no stated requirement for periodic review, except for the Planning
Coordinator. Does this imply an annual review and documentation for all facilities that
are in scope of this standard?
Response: Thank you for your comments.
1. This is exactly what the requirement is. The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners,
Generator Owners, and Distribution Providers; it only explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, section 2 of
PRC-023-1.
2. Again, correct. The methodology and criteria are different between CIP and this standard. The criteria in Attachment B were selected to identify
circuits that present a risk of cascading outages if relay loadability requirements are not met, consistent with the reliability objective of this standard.
3. The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation time frame to
39 months to provide the Facility owners time to budget, procure, and install any protection system equipment modifications and for consistency with
PRC-023-1.
4. As with all standards, entities are expected to be in compliance all the time. Specification of a periodic review for the Transmission Owner, Generator
Owner, and Distribution Provider seems unnecessary; they must naturally perform whatever reviews are necessary to assure continued compliance.
Richard J.
Pacific Gas and
5
Negative
1. R2 is not clear to me. Is the requirement that OSB elements should not prevent the
Padilla
Electric Company
relay from tripping for a fault during overloaded conditions?
2. R6 does not include circuits or facilities that may have been deemed critical facilities for
CIP purposes.
3. R7 timeframe to comply is 24 months. I am not sure that this is sufficient time to get a
job approved and constructed to replace relays on a terminal if they cannot be set to
comply. Few relays 200kV and above did not meet loadability requirements, but I
suspect there are many more at 100-200kv and below 100kV.
4. There is no stated requirement for periodic review, except for the Planning Coordinator.
Does this imply an annual review and documentation for all facilities that are in scope of
this standard?
Response: Thank you for your comments.
1. This is exactly what the requirement is. The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners,
Generator Owners, and Distribution Providers; it only explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, section 2 of
PRC-023-1.
2. Again, correct. The methodology and criteria are different between CIP and this standard. The criteria in Attachment B were selected to identify
circuits that present a risk of cascading outages if relay loadability requirements are not met, consistent with the reliability objective of this standard.
3. The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation time frame to
39 months to provide the Facility owners time to budget, procure, and install any protection system equipment modifications and for consistency with
PRC-023-1.
4. As with all standards, entities are expected to be in compliance all the time. Specification of a periodic review for the Transmission Owner, Generator
January 24, 2011
34

Owner, and Distribution Provider seems unnecessary; they must naturally perform whatever reviews are necessary to assure continued compliance.
Colt Norrish

PacifiCorp

John Apperson

PacifiCorp

Sandra L.
Shaffer
Scott L Smith

PacifiCorp

Response: Thank you for your comments.

Negative

1. PacifiCorp agrees with what it understands are the general concepts contained in Applicability
Section 4.2, Requirements R6 and R7, and Attachment B of the proposed PRC-023-2. Namely,
that: 1) the standard applies to all facilities (defined in Attachment A) above 200 kV and some
facilities below 200 kV; 2) the Planning Coordinator is responsible for identifying the 100 â€“ 200
KV facilities (defined in Attachment A) to which the standard will apply (based on Attachment B);
3) some combination of the Regional Entity and the Planning Coordinator are responsible for
identifying below 100 kV facilities (defined in Attachment A) to which the standard will apply
(based on Attachment B); and 4) Transmission Owners, Generator Owners, and Distribution
Providers that own the facilities that have been deemed applicable are responsible for complying
with the requirements of the standard. If PacifiCorp’s understanding of these concepts is
generally correct, they must be more clearly stated in PRC-023-2.
2. As is currently drafted, the language contained in the applicability section, Requirements R6
and R7, and Attachment B are circular, unclear, and redundant. In order for registered entities
to understand their obligations, the standards must be absolutely clear on what is required and
by whom. PacifiCorp suggests the following:
1) remove R6 because it is redundant with the Applicability Section 4.2 (or vice versa) and clarify
the role of the Planning Coordinator and the application of Attachment B criteria;
2) Applicability Section 4.2.3 and the second bullet in Attachment B appear to contradict as
Section 4.2.3 defines a role for the Planning Coordinator whereas the second bullet in
Attachment B does not -this may be correct for some reason, however, the role of the Planning
Coordinator and the Regional Entity in evaluating facilities below 100 kV must be more clearly
defined. PacifiCorp does not have any substantive issues with the Attachment B criteria.
However, in order to be enforceable, the legal obligations imposed on registered entities under
PRC-023-2 must be more clearly stated.

1. Extensive revisions were made to Attachment B and throughout the standard to improve clarity. The drafting team believes that these responsibilities
are now clearly defined.
2. The drafting team has removed parts 6.1 and 6.2 from Requirement R6 to avoid redundancy, and has revised the Applicability section and Attachment B
based on industry comments to provide clarity. The drafting also has deleted Requirement R7 and modified the Effective Dates section to address the
timeframe in which Facility owners must comply with Requirements R1 through R5 when the Planning Coordinator identifies a circuit for which the
Facility owner must comply with the standard.
Anthony E
ReliabilityFirst
10
Affirmative
ReliabilityFirst votes affirmative but offers the following comments.
Jablonski
Corporation

1.Within the Applicability there are references to PRC-023 –but the version number is
missing.
January 24, 2011

2.R1 should be broken down into two separate requirements. The first requiring the
applicable entities to use one of the criteria. The second requiring the applicable entity to
evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees.
This will make the VSL designations cleaner.
Response: Thank you for your comments.
1) The drafting team has revised the standard as you suggest.
2) The drafting team believes that this comment addresses approved content in PRC-023-1, and is therefore outside the scope of this project.
John C. Allen
Rochester Gas and
1
Negative
Criteria 10 under Requirement 1 could subject the industry to adding phase overcurrent
Electric Corp.
protection to a large number of transformers. Clarification is needed as to the implications of this
requirement.
Response: Thank you for your comments.
The standard does not require that load responsive protection be present to protect for internal faults or through faults. The standard does require that the
protection be set in accordance with criterion 10 if it does exist. The standard has been modified to clarify this point
Rich Salgo

Sierra Pacific Power
Co.

Negative

We cast a negative ballot because the Standard as written, contemplates a fairly complicated
planning study process (Attachment B), to determine which facilities can be included/excluded
from compliance with the relay loadability standard itself. This was done for good intent, and
was a compromise between the industry’s position of 200kV and above applicability, and FERC’s
general position to apply this Standard to everything above 100kV. However, now we have a
recent FERC Order on the definition of BES (Order 743). This Order compels NERC to develop a
new BES definition that is 100kV-based, yet allows for exclusion criteria that NERC is to develop.
As such, this should supersede the criteria proposed in Attachment B. Continuing with Appendix
B as written will cause the unintended consequence of having conflicts between the ultimate BES
list and the list of PRC-023-applicable facilities. It seems they should be the same.

Response: Thank you for your comments.
All circuits that are necessary for operating the interconnected transmission network are not necessarily important for the purposes of PRC-023. The criteria in
Attachment B were selected to identify circuits that present a risk of cascading outages if relay loadability requirements are not met, consistent with the
reliability objective of this standard. Thus, it is expected that the list of circuits identified by applying the criteria in Attachment B will be a subset of the Bulk
Electric System. This standard like all others will need to be reviewed when the new definition of the Bulk Electric System is approved.

January 24, 2011

Long T Duong

Snohomish County
PUD No. 1

January 24, 2011

Affirmative

The District believes to be an unintended consequence – a Catch-22 – from the
interaction of the revised CIP-002-4 Attachment 1’s Criteria 1.4 (Blackstart Resources)
and 1.5 (identified Cranking Paths) with the control center size and facility exceptions in
1.15, 1.16 and 1.17. This interaction will cause many if not all registered TOPs, BAs and
Generation Owners that control Blackstart Resources used in a TOP restoration plan to
become subject to CIP-002 through CIP-009, regardless of entity size. EOP-005 requires
all TOPs to have a restoration plan. The District’s reading of EOP-005 indicates that
each TOP must identify one or more Blackstart Resources. CIP-002-4 Criterion 1.4
requires a TOP to identify each such Blackstart Resource identified in its restoration plan
as a critical asset. Criterion 1.5 requires the identification of certain Cranking Paths as
critical assets. Criterion 1.15 requires that each generation control center or backup
control center used to control a Blackstart Resource identified under Criterion 1.4 be
identified as a critical asset, without any exception for generation control center size
(1500 MW). Criterion 1.16 requires each transmission control center or backup control
center used to control a Cranking Path identified under Criterion 1.5 be identified as a
critical asset, without any exception for TOP control center size. Criterion 1.17 requires
each Balancing Authority control center or backup control center used to control a
Blackstart Resource identified under Criterion 1.4 be identified as a critical asset,
without any exception for Balancing Authority control center size (1500 MW). In effect,
Criterion 1.4 swallows all exceptions created under 1.15 through 1.17, with the possible
exception of a generation-only BA that does not have any Blackstart Resource
obligations to its TOP. All vertically integrated utilities would be responsible for CIP002 through CIP-009, including small BAs and TOPs that do not own any other Critical
Assets. To address this problem, we propose the following edits to 1.4 and 1.5 shown in
redline CAPS/strikeout: 1.4. Each Blackstart Resource identified in the RESTORATION
PLAN FOR A Transmission Operator’s restoration plan SERVING LOAD OR
GENERATION EQUAL TO OR GREATER THAN AN AGGREGATE OF 1500 MW
IN A SINGLE INTERCONNECTION. 1.5. The Facilities comprising the Cranking
Paths and meeting the initial switching requirements from the Blackstart Resource(S)
IDENTIFIED IN 1.4. to the first interconnection point of the generation unit(s) to be
started, or up to the point on the Cranking Path where two or more path options exist, as
identified in the Transmission Operator's restoration plan. This surgical approach ensures
that generation, TOP and BA control centers with responsibility for other critical
generation and transmission assets are still responsible for full CIP-002-4 through CIP009 compliance. However, small BA/TOP systems with no initial obligations to the RC
37

and larger TOPs for regional restoration would not be deemed “critical.” The experience
of these smaller systems is that their restoration obligations have not been relied upon to
restore the BES, but rather to start generation to serve local load after a system
separation – and then to wait for direction from the RC on resynchronization with the
rest of the BES, once voltage and frequency are stabilized. While we recognize that
cyber events may have an impact on the availability of resources, the fundamental fact is
the vast majority of Blackstart Resources and control centers will be protected under
CIP-002 through -009, because they will be classified as Critical/High Impact under the
proposed criteria, as revised above. Thus the revised criteria support rather than
undermine the distinction between categorization of big iron/big aluminum resources
and their associated control centers as Critical or High Impact in the development of
CIP-002-4. The categorization and development of security controls for smaller
resources as either medium or low impact for the BES, should be addressed through
development of additional bright line criteria and associated security controls in the next
phase of this project (CIP-002-5 or CIP-010/011.)
Response: Thank you for your comments.
The drafting team notes that the criteria in Attachment B are intentionally different than the CIP requirements for identifying critical facilities. It appears that
the comments submitted would be more appropriately submitted to the Project 2008-06 ― Cyber Security ― Order 706 drafting team.
Charles H
Southwest Power
2
Negative
SPP supports the comments submitted by the ISO RTO Council Standards Review Committee
Yeung
Pool
which raise many concerns on the requirements proposed.
Response: Thank you for your comments.
Please see our response to the comments submitted by the ISO RTO Council Standards Review Committee.
Travis Metcalfe Tacoma Public
3
Negative
1. Transmission or Transformers that normally would not be considered BES assets are
Utilities
subject to inclusion by the Planning Coordinator. The criteria for inclusion have not been

developed yet.
2. Attachment A Section 1.6 was added due to FERC Order 733, but it is still vague what
includes “Supervisory Elements”. Please clarify supervisory elements (Does it include
RTUs?)
3. Detailed direction about relay setting methodology could be expanded to 110-kV
level by this revision. Much more research should be devoted to such detailed
changes to evaluate impact to other protection and operation constraints, before
such settings are mandatory.
January 24, 2011

4. The new requirement (R2) may present conflicting choices for a relay engineer,
since out-of-step blocking is technically challenging to set, sense and discriminate
from certain loading and fault conditions.

Response: Thank you for your comments.
1. The NERC Statement of Compliance Registry Criteria permits application of NERC Reliability Standards to certain facilities operated below 100 kV, such
as for transmission elements operated below 100 kV that are included on a critical facilities list defined by the Regional Entity. The test by which the
Regional Entity may make this determination is outside the scope of this standard. The criteria by which the Planning Coordinators determine for which
of the circuits on the list the applicable entities must comply with the standard are defined in Attachment B.
2. Attachment A, Section 1.6 has been modified to include supervisory elements only as they apply to current-based, communication-assisted schemes
where the scheme is capable of tripping for loss of communications. The drafting team believes this modification provides clarity that this section does
not apply to RTUs and other applications.
3. The drafting team understands your concern and will place this item in the issues database for future consideration in the next general revision of the
standard. However, the drafting team notes that PRC-023-1 already applies to lines operated at 100 kV to 200 kV and the drafting team does not
believe that a significant number of sub-100 kV circuits will be impacted. As such, the drafting team disagrees that more research is required prior to
implementing PRC-023-2.
4. The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners, and Distribution Providers; it
only explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, Section 2 of PRC-023-1.
Keith Morisette Tacoma Public
4
Negative
Tacoma Power is submitting a Negative vote due to the following concerns: ·
Utilities
1. Transmission or Transformers that normally would not be considered BES assets are

subject to inclusion by the Planning Coordinator. The criteria for inclusion have not been
developed yet.
2. Attachment A Section 1.6 was added due to FERC Order 733, but it is still vague what
includes “Supervisory Elements”. Please clarify supervisory elements (Does it include
RTUs?)
3. Detailed direction about relay setting methodology could be expanded to 110-kV level
by this revision. Much more research should be devoted to such detailed changes to
evaluate impact to other protection and operation constraints, before such settings are
mandatory.
January 24, 2011

4. The new requirement (R2) may present conflicting choices for a relay engineer, since
out-of-step blocking is technically challenging to set, sense and discriminate from certain
loading and fault conditions. Thank you for consideration of these concerns.

Response: Thank you for your comments.
1. The NERC Statement of Compliance Registry Criteria permits application of NERC Reliability Standards to certain facilities operated below 100 kV, such
as for transmission elements operated below 100 kV that are included on a critical facilities list defined by the Regional Entity. The test by which the
Regional Entity may make this determination is outside the scope of this standard. The criteria by which the Planning Coordinators determine for which
of the circuits on the list the applicable entities must comply with the standard are defined in Attachment B.
2. Attachment A, Section 1.6 has been modified to include supervisory elements only as they apply to current-based, communication-assisted schemes
where the scheme is capable of tripping for loss of communications. The drafting team believes this modification provides clarity that this section does
not apply to RTUs and other applications.
3. The drafting team understands your concern and will place this item in the issues database for future consideration in the next general revision of the
standard. However, the drafting team notes that PRC-023-1 already applies to lines operated at 100 kV to 200 kV and the drafting team does not
believe that a significant number of sub-100 kV circuits will be impacted. As such, the drafting team disagrees that more research is required prior to
implementing PRC-023-2.
4. The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners, and Distribution Providers; it
only explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, Section 2 of PRC-023-1.
Michael C Hill
Tacoma Public
6
Negative
1. Transmission or Transformers that normally would not be considered BES assets are
Utilities
subject to inclusion by the Planning Coordinator. The criteria for inclusion have not been

developed yet.
2. Attachment A Section 1.6 was added due to FERC Order 733, but it is still vague what
includes “Supervisory Elements”. Please clarify supervisory elements (Does it include
RTUs?)
3. Detailed direction about relay setting methodology could be expanded to 110-kV level
by this revision. Much more research should be devoted to such detailed changes to
evaluate impact to other protection and operation constraints, before such settings are
mandatory.
January 24, 2011

4. The new requirement (R2) may present conflicting choices for a relay engineer, since
out-of-step blocking is technically challenging to set, sense and discriminate from certain
loading and fault conditions.

Response: Thank you for your comments.
1. The NERC Statement of Compliance Registry Criteria permits application of NERC Reliability Standards to certain facilities operated below 100 kV, such
as for transmission elements operated below 100 kV that are included on a critical facilities list defined by the Regional Entity. The test by which the
Regional Entity may make this determination is outside the scope of this standard. The criteria by which the Planning Coordinators determine for which
of the circuits on the list the applicable entities must comply with the standard are defined in Attachment B.
2. Attachment A, Section 1.6 has been modified to include supervisory elements only as they apply to current-based, communication-assisted schemes
where the scheme is capable of tripping for loss of communications. The drafting team believes this modification provides clarity that this section does
not apply to RTUs and other applications.
3. The drafting team understands your concern and will place this item in the issues database for future consideration in the next general revision of the
standard. However, the drafting team notes that PRC-023-1 already applies to lines operated at 100 kV to 200 kV and the drafting team does not
believe that a significant number of sub-100 kV circuits will be impacted. As such, the drafting team disagrees that more research is required prior to
implementing PRC-023-2.
4. The drafting team notes that Requirement R2 does not add a new obligation on Transmission Owners, Generator Owners, and Distribution Providers; it
only explicitly states in PRC-023-2 an obligation that presently is included in Attachment A, Section 2 of PRC-023-1.
Larry D.
Texas Reliability
10
Negative
1. In R1, criterion 9 is missing some words at the end. We think it is supposed to say “. .
Grimm
Entity
. from the load to the system under any system configuration.”

2. In R1, criterion 12(c), it appears that the reference should be changed from “criterion
12” to “criterion 12(b)”.
3. In Attachment B, criterion B1, “Texas Interconnection” should be changed to
“ERCOT Interconnection.” That is the correct name of this Interconnection. (FYI, the
ERCOT Interconnection does not include several parts of the Texas BES, which are in
WECC, SPP, and SERC.)
4. In R1, criteria 1, 4, and 10, the draft specifies that Facility Ratings are to be
“expressed in amperes.” In our experience these ratings are ordinarily expressed in
MVA. In criteria 11, a rating is referenced, but the units are not specified. We suggest
January 24, 2011

either (a) not specifying units for these ratings in the standard, or (b) specifying “MVA”
rather than “amperes.”
5. In R1, criteria 10 and 11, the references to “operator established emergency
transformer rating” should be changed to “owner established emergency transformer
rating.” Note that FAC-008 and FAC-009 call on the Transmission Owner and Generator
Owner entities to establish Facility Ratings.
6. In R5, why is the Regional Entity designated to receive a list of facilities with relays
set according to criterion 12? Texas RE does not ordinarily act as a clearinghouse for
this kind of information. If the intention is to share this information with other entities,
this list should be provided to the Reliability Coordinator or some other appropriate
functional entity, rather than to the Regional Entity.
7. In Attachment B, criterion B3, “plant owner” should be changed to “Generator
Owner” and “Transmission Entity” should be changed to “Transmission Owner,” in
order to clearly designate the responsible entities.
8. In Attachment B, criterion B4, the reference to “power flow analysis” should be
changed to “power flow assessment,” in order to make it consistent with the term used in
R6.
9. In Attachment B, criterion B4, the second bullet is unclear as written. We suggest
changing it to read as follows: “For circuits operated between 100 kV and 200 kV,
evaluate the post-contingency loading against the Facility Rating after contingency
evaluations per TPL-003, Category A, B, and C3 with the near-term load flow case.”
Response: Thank you for your comments
1. The text has been corrected.
2. The drafting team believes that this comment addresses approved content in PRC-023-1, and is therefore outside the scope of this project. The
drafting team will place this item in the issues database for future consideration in the next general revision of the standard.
3. In response to other comments, Attachment B, criterion B1 has been revised to delete the reference to the Texas Interconnection.
4. The drafting team believes that this comment addresses existing content in PRC-023-1, and is therefore outside the scope of this project.
5. The drafting team believes that this comment addresses existing content in PRC-023-1, and is therefore outside the scope of this project.
6. The Regional Entity (RE), via the delegation agreements, is a part of the ERO; thus, by submitting the information to the RE, the ERO will have the
information available to respond to requests from users, owners, and operators of the BES.
7. This criterion references Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001, and therefore refers to entities consistent with the
January 24, 2011

description in NUC-001 which does not refer to NERC Functional Model entities.
8. The drafting team notes that the power flow analysis required in criterion B4 is one aspect of the assessment identified in Requirement R6. Criterion B4
therefore is not inconsistent with Requirement R6.
9. A number of changes have been made to criterion B4 in response to industry comments. While the drafting team has not incorporated this suggestion,
we believe the modifications to the criterion provide clarity desired by the commenter.
Keith V.
Tri-State G & T
1
Negative
Reference Tri-State Generation & Transmission Assn., Inc. comments submitted to NERC via the
Carman
Association, Inc.
Project 2010-13 Formal Comment link.
Janelle
Tri-State G & T
3
Negative
Reference Tri-State Generation and Transmission Assn., Inc. Formal comments submitted to
Marriott
Association, Inc.
NERC electronically via the Project 2010-13 Formal Comment link. Thank you.
Response: Thank you for your comments.
Please refer to the drafting team responses in the Consideration of Comments document.
Jonathan
United Illuminating
1
Negative
The drafting team should include a criteria for Phase Angle Regulators and Series reactors.
Appelbaum
Co.
These are types of transformers and for clarity purposes should be called out specifically.
Response: Thank you for your comments.
The drafting team believes that the phase angle regulating transformers are already included in the standard in Criteria 10 and 11, and that series reactors are
already included as part of the element in which they are inserted. This comment will be considered as we prepare future versions of the standard.
Allen Klassen
Westar Energy
1
Affirmative
Please define the term "mechanical withstand" used in B.R1.10.
Response: Thank you for your comments.
The mechanical withstand is defined is IEEE C57.109-1993, IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration and a reference to
this standard has been added as a footnote to address your concerns.
Brandy A Dunn Western Area
1
Negative
1. The different wording regarding applicability to transmission lines between 100-kV
Power
and 200-kV is confusing as it is not clear from these statements whether or not the
Administration
Planning Coordinator makes this determination. Under “Applicability”, 4.2.2 states:

Transmission lines operated at 100 kV to 200 kV that the Planning Coordinator has
determined are required to comply with this standard. Attachment B indicates applicable
circuits are: Transmission lines operated at 100 kV to 200 kV [….].
2. Similarly the different wording regarding applicability to transformers having low
voltage terminals between 100-kV and 200-kV is confusing as it is not clear from these
statements whether or not the Planning Coordinator makes this determination. Under
“Applicability”, 4.2.5 states: Transformers with low voltage terminals connected at 100
kV to 200 kV that the Planning Coordinator has determined are required to comply with
this standard. Attachment B indicates applicable circuits are: [….] transformers with low
voltage terminals connected at 100 kV to 200 kV
January 24, 2011

3. Regarding the former comments 1 and 2, Attachment B could reference 4.2.1 - 4.2.6,
or repeat them exactly, unless there is another intent of describing applicability again
under Attachment B.
4. In “B. Requirements R1.”: suggest the following mod from: “power factor angle of 30
degrees.” to: “power factor angle of 30 degrees, where the power factor angle is material
to the operation of the relay such as with mho type characteristics.”
5. 6.1 and 6.2 are further re-statements of applicability criteria. It would be less
confusing to have these appear one place in the document and reference them elsewhere,
or repeat them identically each time they are used.
6. Attachment A - The meaning of 1.6 and its relationship to the second bullet under 2.1
is unclear and confusing.
Response: Thank you for your comments.
1. The drafting team has divided the Applicability section to differentiate between circuits subject to Requirement R6 (the circuits to which the Planning
Coordinator must apply Attachment B) and the circuits subject to Requirements R1 through R5 (the circuits identified by the Planning Coordinator
through the Application of Attachment B). The drafting team believes this change addresses the commenter’s concern.
2. The drafting believes the changes to the Applicability section address this concern also.
3. The drafting team has modified Attachment B to use the same description as the circuits subject to Requirement R6 in the Applicability section.
4. The drafting team believes that this comment addresses existing content in PRC-023-1, and is therefore outside the scope of this project.
5. 1)
The drafting team has eliminated parts 6.1 and 6.2 from Requirement R6. The drafting team understands that repeating this information in
Requirement R6 and in Attachment B is redundant and potentially confusing. In addition, the drafting team has revised the text in Attachment B to
more clearly convey the intent.
6. The drafting team has modified believes that this relationship is clear. Section 1.6 specifically includes supervisory elements associated with currentbased, communication-assisted schemes where the scheme is capable of tripping for loss of communications, and 2.1 (second bullet) excludes all
elements only enabled during a loss of communication, with the exception of supervisory elements included in Section 1.6
Forrest Brock
Western Farmers
1
Affirmative
WFEC recognizes the work of the SDT in composing a draft standard for relay loadability that
Electric Coop.
displays the team's effort to keep the requirements within the standard focused on achieving
reliability for the BES.
Response: Thank you for your comment.
Gregory L
Pieper

Xcel Energy, Inc.

Michael Ibold

Xcel Energy, Inc.

January 24, 2011

Negative

Sections 4.2.3 and 4.2.6, in the applicability section, are of concern to us because they include
facilities that would not otherwise be part of the Bulk Electric System (i.e. facilities operating less
than 100 kV). Other drafting teams have contemplated including generating units connected at
44

Liam Noailles

Xcel Energy, Inc.

David F.
Lemmons

Xcel Energy, Inc.

Response: Thank you for your comments.

less than 100 kV, and have been advised that if they did that, Generator Owners that were not
Registered Entities with NERC would have to register and would be required to comply with ALL
Generator Owner requirements in ALL of the NERC standards. This same risk exists under the
currently proposed PRC-023-2. We suggest that a requirement be added to require the PA to
notify the unregistered entity, if their facility has been determined to be critical. In addition,
there should be additional time permitted for those entities to get into compliance and that
should be reflected in the implementation plan.

The drafting team understands the concern with including facilities operated below 100 kV; however, the NERC Statement of Compliance Registry Criteria does
allow Regional Entities the ability to identify such facilities operated below 100 kV as required to comply with NERC Reliability Standards. The drafting team has
replaced the phrase “critical for the purposes of the Compliance Registry” with text from the ¶60 of Order No. 733, which references text in section III.d.2 of
the NERC Statement of Compliance Registry Criteria, so the second category of circuits to be evaluated now refers to transmission lines and transformers
operated below 100 kV “that are included on a critical facilities list defined by the Regional Entity.” The drafting team made corresponding modifications to the
Applicability section.

January 24, 2011

PRC-023-2 Mapping of Requirements from PRC-023-1 and
Directed Modifications in Order No. 733
Mapping of PRC-023-1 to PRC-023-2

Requirement in the Existing PRC-023-1

Location in
PRC-023-2
(1st Posting)

R1. Each Transmission Owner, Generator Owner, and
Distribution Provider shall use any one of the following
criteria (R1.1 through R1.13) for any specific circuit terminal
to prevent its phase protective relay settings from limiting
transmission system loadability while maintaining reliable
protection of the Bulk Electric System for all fault conditions.
Each Transmission Owner, Generator Owner, and
Distribution Provider shall evaluate relay loadability at 0.85
per unit voltage and a power factor angle of 30 degrees:

Requirement
R1

Requirements
R1.1 through
R1.13 are now
criteria 1
through 13
under
Requirement
R1

116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Location in
PRC-023-2
(2nd Posting)

Needed for
Reliability

Requirement
R1

Yes

Requirements
R1.1 through
R1.13 are now
criteria 1
through 13
under
Requirement
R1

Yes

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of PRC-023-1 to PRC-023-2

Requirement in the Existing PRC-023-1

Location in
PRC-023-2
(1st Posting)

Location in
PRC-023-2
(2nd Posting)

Needed for
Reliability

with R1.3, using the full line inductive reactance.
R1.5. Set transmission line relays on weak source systems so
they do not operate at or below 170% of the maximum endof-line three-phase fault magnitude (expressed in amperes).
R1.6. Set transmission line relays applied on transmission
lines connected to generation stations remote to load so they
do not operate at or below 230% of the aggregated generation
nameplate capability.
R1.7. Set transmission line relays applied at the load center
terminal, remote from generation stations, so they do not
operate at or below 115% of the maximum current flow from
the load to the generation source under any system
configuration.
R1.8. Set transmission line relays applied on the bulk systemend of transmission lines that serve load remote to the system
so they do not operate at or below 115% of the maximum
current flow from the system to the load under any system
configuration.
R1.9. Set transmission line relays applied on the load-end of
transmission lines that serve load remote to the bulk system
so they do not operate at or below 115% of the maximum
current flow from the load to the system under any system
configuration.
R1.10. Set transformer fault protection relays and
transmission line relays on transmission lines terminated only
with a transformer so that they do not operate at or below the
greater of:
- 150% of the applicable maximum transformer
nameplate rating (expressed in amperes), including the
forced cooled ratings corresponding to all installed
supplemental cooling equipment.
- 115% of the highest operator established emergency
transformer rating.
R1.11. For transformer overload protection relays that do not
comply with R1.10 set the relays according to one of the
following:
- Set the relays to allow the transformer to be operated at
an overload level of at least 150% of the maximum
applicable nameplate rating, or 115% of the highest
operator established emergency transformer rating,
whichever is greater. The protection must allow this
overload for at least 15 minutes to allow for the operator
January 24, 2011

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of PRC-023-1 to PRC-023-2

Requirement in the Existing PRC-023-1

Location in
PRC-023-2
(1st Posting)

Location in
PRC-023-2
(2nd Posting)

Needed for
Reliability

to take controlled action to relieve the overload.
- Install supervision for the relays using either a top oil or
simulated winding hot spot temperature element. The
setting should be no less than 100° C for the top oil or
140° C for the winding hot spot temperature3.
R1.12. When the desired transmission line capability is
limited by the requirement to adequately protect the
transmission line, set the transmission line distance relays to a
maximum of 125% of the apparent impedance (at the
impedance angle of the transmission line) subject to the
following constraints:
R1.12.1. Set the maximum torque angle (MTA) to 90
degrees or the highest supported by the manufacturer.
R1.12.2. Evaluate the relay loadability in amperes at the
relay trip point at 0.85 per unit voltage and a power factor
angle of 30 degrees.
R1.12.3. Include a relay setting component of 87% of the
current calculated in R1.12.2 in the Facility Rating
determination for the circuit.
R1.13. Where other situations present practical limitations on
circuit capability, set the phase protection relays so they do
not operate at or below 115% of such limitations.
R2. The Transmission Owner, Generator Owner, or
Distribution Provider that uses a circuit capability with the
practical limitations described in R1.6, R1.7, R1.8, R1.9,
R1.12, or R1.13 shall use the calculated circuit capability as
the Facility Rating of the circuit and shall obtain the
agreement of the Planning Coordinator, Transmission
Operator, and Reliability Coordinator with the calculated
circuit capability.

Requirement
R3

Yes

R3. The Planning Coordinator shall determine which of the
facilities (transmission lines operated at 100 kV to 200 kV
and transformers with low voltage terminals connected at 100
kV to 200 kV) in its Planning Coordinator Area are critical to
the reliability of the Bulk Electric System to identify the
facilities from 100 kV to 200 kV that must meet Requirement
1 to prevent potential cascade tripping that may occur when
protective relay settings limit transmission loadability.

Requirement
R6

Yes

January 24, 2011

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of PRC-023-1 to PRC-023-2
Location in
PRC-023-2
(1st Posting)

Location in
PRC-023-2
(2nd Posting)

R3.1. The Planning Coordinator shall have a process to
determine the facilities that are critical to the reliability of the
Bulk Electric System.
R3.1.1. This process shall consider input from adjoining
Planning Coordinators and affected Reliability
Coordinators.

Determination
of facilities
that must
comply with
this standard
is now
contained in
Attachment B

Yes

R3.2. The Planning Coordinator shall maintain a current list
of facilities determined according to the process described in
R3.1.

Requirement
R6, Part 6.3

Requirement
R6, Part 6.1

Yes

R3.3. The Planning Coordinator shall provide a list of
facilities to its Reliability Coordinators, Transmission
Owners, Generator Owners, and Distribution Providers within
30 days of the establishment of the initial list and within 30
days of any changes to the list.

Requirement
R6, Part 6.5

Requirement
R6, Part 6.2

Yes

Requirement in the Existing PRC-023-1

Needed for
Reliability

Mapping of Directed Changes in Order No. 733
Paragraph
in Order
No. 733

Text

Location in
PRC-023-2
(1st Draft)

Location in
PRC-023-2
(2nd Draft)

Needed for
Reliability

With respect to sub-100 kV facilities, we adopt the
NOPR proposal and direct the ERO to modify PRC023-1 to apply an “add in” approach to sub-100 kV
facilities that are owned or operated by currentlyRegistered Entities or entities that become Registered
Entities in the future, and are associated with a
facility that is included on a critical facilities list
defined by the Regional Entity. We also direct that
additions to the Regional Entities’ critical facility list
be tested for their applicability to PRC-023-1 and
made subject to the Reliability Standard as
appropriate.

Requirement
R6 and
Attachment
B

Yes

Finally, pursuant to section 215(d)(5) of the FPA, we

Requirement

Yes

January 24, 2011

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of Directed Changes in Order No. 733
Location in
PRC-023-2
(1st Draft)

Location in
PRC-023-2
(2nd Draft)

direct the ERO to modify Requirement R3 of the
Reliability Standard to specify the test that planning
coordinators must use to determine whether a sub200 kV facility is critical to the reliability of the
Bulk-Power System. We direct the ERO to file its
test, and the results of applying the test to a
representative sample of utilities from each of the
three Interconnections, for Commission approval no
later than one year from the date of this Final Rule.

R6 and
Attachment
B

Finally, commenters argue that there should be some
mechanism for entities to challenge criticality
determinations. We agree that such a mechanism is
appropriate and direct the ERO to develop an appeals
process (or point to a process in its existing
procedures) and submit it to the Commission no later
than one year after the date of this Final Rule.

To be
addressed
outside
PRC-023-2

Yes

162

We agree with the PSEG Companies and direct the
ERO to consider “islanding” strategies that achieve
the fundamental performance for all islands in
developing the new Reliability Standard addressing
stable power swings.

Considered
in Phase I;
will be
addressed in
Phase III

Yes

186

However, we will adopt the NOPR proposal to direct
the ERO to modify PRC-023-1 to require that
transmission owners, generator owners, and
distribution providers give their transmission
operators a list of transmission facilities that
implement sub-requirement R1.2.

Requirement
R4

Yes

203

We adopt the NOPR proposal and direct the ERO to
modify sub-requirement R1.10 so that it requires
entities to verify that the limiting piece of equipment
is capable of sustaining the anticipated overload for
the longest clearing time associated with the fault.

Requirement
R1, criterion
10

Yes

224

While we are not adopting the NOPR proposal, we
direct the ERO to document, subject to audit by the
Commission, and to make available for review to
users, owners and operators of the Bulk-Power
System, by request, a list of those facilities that have
protective relays set pursuant sub-requirement R1.12.

Requirement
R5 collects
data; ERO to
provide list
outside
PRC-023-2

Yes

Paragraph
in Order
No. 733

Text

January 24, 2011

Needed for
Reliability

PRC-023-2 Mapping of Requirements from PRC-023-1 and Directed Modifications in Order No. 733

Mapping of Directed Changes in Order No. 733
Paragraph
in Order
No. 733

Text

Location in
PRC-023-2
(1st Draft)

Location in
PRC-023-2
(2nd Draft)

Needed for
Reliability

237

We adopt the NOPR proposal and direct the ERO to
modify the Reliability Standard to add the Regional
Entity to the list of entities that receive the critical
facilities list. [sub-requirement R3.3]

Requirement
R6, Part 6.5

Requirement
R6, Part 6.2

Yes

244

We adopt the NOPR proposal and direct the ERO to
include section 2 of Attachment A in the modified
Reliability Standard as an additional Requirement
with the appropriate violation risk factor and
violation severity level.

Requirement
R2

Yes

264

After further consideration, and in light of the
comments, we will not direct the ERO to remove any
exclusion from section 3, except for the exclusion of
supervising relay elements in section 3.1.
Consequently, we direct the ERO to revise section 1
of Attachment A to include supervising relay
elements on the list of relays and protection systems
that are specifically subject to the Reliability
Standard.

Attachment
A, Section
1.6

Yes

283

Additionally, in light of our directive to the ERO to
expand the Reliability Standard’s scope to include
sub-100 kV facilities that Regional Entities have
already identified as necessary to the reliability of the
Bulk-Power System through inclusion in the
Compliance Registry, we direct the ERO to modify
the Reliability Standard to include an implementation
plan for sub-100 kV facilities.

Implementat
ion Plan

Yes

284

We also direct the ERO to remove the exceptions
footnote from the “Effective Dates” section.

Footnote 1
removed
from the
“Effective
Dates:
section

Yes

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels
PRC-023-2 — Transmission Relay Loadability
This document provides the justification for assignment of Violation Risk Factors (VRFs) and Violation
Severity Levels (VSLs), identifying how each proposed VRF and VSL meets NERC’s criteria and
FERC’s Guidelines. NERC’s criteria for setting VRFs and VSLs; FERC’s five guidelines (G1 – G5) for
approving VRFs; and FERC’s four guidelines (G1-G4) for setting VSLs are provided at the end of this
document.
VRF and VSL Justifications for R1

Proposed VRF

High

NERC VRF Discussion

The proposed requirement, R1, states that each Transmission Owner,
Generator Owner, and Distribution Provider shall apply one of several
criteria to ensure that its load-responsive relaying does not trip due to load
responsive conditions. The VRF for Requirement R1 is a “High” because,
should the load-responsive relaying trip improperly due to load conditions,
it could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk
electric system at an unacceptable risk of instability, separation, or
cascading failures

FERC VRF G1
Discussion

Guideline 1- Consistency w/ Blackout Report
This requirement is directly related to NERC Recommendation 8a and US
Canada Power System Outage Task Force Recommendation 21a, and is
developed explicitly to address those recommendations. A High VRF is
consistent with the role that relay loadability played in contributing to the
August 14, 2003 Northeast Blackout.

FERC VRF G2
Discussion

Guideline 2- Consistency within a Reliability Standard
Requirement R2 has a similar reliability objective and is assigned a High
VRF

FERC VRF G3
Discussion

Guideline 3- Consistency among Reliability Standards
Not applicable. There are no other NERC Reliability Standards that
address similar reliability goals.

FERC VRF G4
Discussion

Guideline 4- Consistency with NERC Definitions of VRFs
The proposed VRF is consistent with the NERC definitions of VRFs because
as described above the requirement ensures that load-responsive protective
relays will not improperly operate during the loading conditions described
within the R1 criteria. This requirement if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures.

FERC VRF G5
Discussion

Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation
The proposed requirement does not co-mingle more than one obligation and
therefore this guideline does not apply.

Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
VRF and VSL Justifications for R1
Proposed Severe VSL

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

The responsible entity did not evaluate relay loadability at 0.85 per unit
voltage and a power factor angle of 30 degrees.
The proposed VSL for Requirement is consistent with the approved VSL for
the similar Requirement R1 within PRC-023-1.

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

Guideline 2a:
The proposed VSL is binary and assigns a “Severe” category for the
violation of the requirement.

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

The proposed VSL is consistent with the corresponding Requirement, R1.

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

The proposed VSL is based on a single violation and not a cumulative
number of violations.

January 24, 2011

Guideline 2b:
The proposed VSL for Requirement R2 does not contain ambiguous
language.

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

VRF and VSL Justifications for R2
Proposed VRF

High

NERC VRF Discussion

The proposed requirement, R2, states that each Transmission Owner,
Generator Owner, and Distribution Provider shall ensure that its out-of-step
blocking elements allow tripping of phase protective relays for faults that
occur during the loading conditions used to verify transmission line relay
loadability per Requirement R1. The VRF for Requirement R2 is a “High”
because a protection system if inhibited from operating by the out of step
blocking could prevent it from operating for fault conditions. In a planning
time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could
hinder restoration to a normal condition.
Guideline 1- Consistency w/ Blackout Report
Not applicable. Out-of-step blocking elements did not prevent tripping of
phase protective relays during the August 14, 2003 Northeast Blackout.
Guideline 2- Consistency within a Reliability Standard
Requirement R2 references Requirement R1 and both requirements are
assigned a “High” VRF.

FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

FERC VRF G5
Discussion

Guideline 3- Consistency among Reliability Standards
Not applicable. There are no other NERC Reliability Standards that
address similar reliability goals.
Guideline 4- Consistency with NERC Definitions of VRFs
The proposed VRF is consistent with the NERC definitions of VRFs because
as described above the requirement ensures that out-of-step blocking
elements allow tripping of phase protective relays for faults that occur
during the loading conditions used to verify transmission line relay
loadability per Requirement R1. This requirement is in the planning time
frame and if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of
instability, separation, or cascading failures, or could hinder restoration to
a normal condition.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation
The proposed requirement does not co-mingle more than one obligation and
therefore this guideline does not apply.

Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

FERC VSL G1
Violation Severity Level

The proposed VSL for Requirement R2 does not lower the current level of
compliance regarding out of step blocking elements. Out-of-step blocking

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
VRF and VSL Justifications for R2
Assignments Should Not elements are addressed in Requirement R1 in PRC-023-1. Out-of-step
Have the Unintended
blocking has been included in a separate requirement in PRC-023-2 per
Consequence of
Order 733 and the VSLs for Requirements R1 and R2 are consistent.
Lowering the Current
Level of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should
Ensure Uniformity and
Consistency in the
Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements
Is Not Consistent
Guideline 2b: Violation
Severity Level
Assignments that
Contain Ambiguous
Language

Guideline 2a:
The proposed VSL is binary and assigns a “Severe” category for the
violation of the requirement.

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

The proposed VSL is consistent with the corresponding Requirement, R2.

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

The proposed VSL is based on a single violation and not a cumulative
number of violations.

January 24, 2011

Guideline 2b:
The proposed VSL for Requirement R2 does not contain ambiguous
language.

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

VRF and VSL Justifications for R3
Proposed VRF

Medium

NERC VRF Discussion

The proposed VRF is consistent with the NERC definition for lower VRF
because the proposed requirement requires that each Transmission Owner,
Generator Owner, and Distribution Provider that uses a circuit capability
with the practical limitations described in Requirement R1, criterion 6, 7, 8,
9, 12, or 13 shall use the calculated circuit capability as the Facility Rating
of the circuit and shall obtain the agreement of the Planning Coordinator,
Transmission Operator, and Reliability Coordinator with the calculated
circuit capability.. Because the purpose of the requirement is to assure that
the recipient entities are aware of, and have agreed with, modified Facility
Ratings, this requirement, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under
emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability, separation, or
cascading failures, nor to hinder restoration to a normal condition.
Guideline 1- Consistency w/ Blackout Report
Not applicable. This criteria to which this requirement is related did not
exist at the time of the August 14, 2003 Northeast Blackout.

FERC VRF G1
Discussion

FERC VRF G2
Discussion

Guideline 2- Consistency within a Reliability Standard
Not applicable. There are no other requirements in this standard that
address similar reliability goals.

FERC VRF G3
Discussion

Guideline 3- Consistency among Reliability Standards
Requirement R2 of FAC-009-1 states that the Transmission Owner and
Generator Owner shall each provide Facility Ratings for its solely and
jointly owned Facilities that are existing Facilities, new Facilities,
modifications to existing Facilities and re-ratings of existing Facilities to its
associated Reliability Coordinator(s), Planning Authority(ies), Transmission
Planner(s), and Transmission Operator(s) as scheduled by such requesting
entities. This data exchange requirement is assigned a Medium VRF.

FERC VRF G4
Discussion

Guideline 4- Consistency with NERC Definitions of VRFs
Because the purpose of the requirement is to ensure that entities have
consistent Facility Ratings in order to operate the BES effectively, this VRF
is consistent with the NERC Definition of a Medium VRF.

FERC VRF G5
Discussion

Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation
The proposed requirement does not co-mingle more than one obligation and
therefore this guideline does not apply.

Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
VRF and VSL Justifications for R3
OR
The responsible entity did not obtain the agreement of the Planning
Coordinator, Transmission Operator, and Reliability Coordinator with the
calculated circuit capability.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance

This VSL is consistent with the VSL assigned to Requirement R2 of approved
PRC-023-1, which is essentially identical and is replaced by this
requirement.

Guideline 2a:
The VSL is binary and establishes a severe level.

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

The proposed VSL is consistent with the corresponding Requirement R3.

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

The proposed VSL is based on a single violation and not a cumulative
number of violations.

January 24, 2011

Guideline 2b:
The proposed VSL for Requirement R3 does not contain ambiguous
language.

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

VRF and VSL Justifications for R4
Proposed VRF

Lower

NERC VRF Discussion

The proposed VRF is consistent with the NERC definition for lower VRF
because the proposed requirement requires that each Transmission Owner,
Generator Owner, and Distribution Provider that chooses to utilize
Requirement R1 criterion 2 as the basis for verifying transmission line relay
loadability must provide its Planning Coordinator, Transmission Operator,
and Reliability Coordinator with a list of circuits associated with those
transmission line relays at least once each calendar year, with no more than
15 months between reports. Because the purpose of the requirement is to
share information with other entities through the exchange of a report the
requirement is considered administrative in nature and consistent with the
definition of a lower VRF.
Guideline 1- Consistency w/ Blackout Report
Not applicable. This criterion to which this requirement is related did not
exist at the time of the August 14, 2003 Northeast Blackout.
Guideline 2- Consistency within a Reliability Standard
Requirement R5 has a similar reliability objective and is assigned a lower
VRF.

FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion

R4
FERC VRF G4
Discussion

FERC VRF G5
Discussion

Guideline 3- Consistency among Reliability Standards
Requirement R3 of PRC-015-0 states that the Transmission Owner,
Generator Owner, and Distribution Provider that owns an SPS shall provide
documentation of SPS data and the results of studies that show compliance
of new or functionally modified SPSs with NERC Reliability Standards and
Regional Reliability Organization criteria to affected Regional Reliability
Organizations and NERC on request (within 30 calendar days). This data
exchange requirement is assigned a Lower VRF.
Guideline 4- Consistency with NERC Definitions of VRFs
Because the purpose of the requirement is to share information with other
entities through the exchange of a report the requirement is considered
administrative in nature and consistent with the definition of a lower VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation
The proposed requirement does not co-mingle more than one obligation and
therefore this guideline does not apply.

Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

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

This VLS does not lower the current level of compliance because this is a
new Requirement that did not exist in PRC-023-1.

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
VRF and VSL Justifications for R4
Level of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should
Ensure Uniformity and
Consistency in the
Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements
Is Not Consistent
Guideline 2b: Violation
Severity Level
Assignments that
Contain Ambiguous
Language

Guideline 2a:
The VSL is binary and establishes a severe level.

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

The proposed VSL is consistent with the corresponding Requirement R4.

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

The proposed VSL is based on a single violation and not a cumulative
number of violations.

January 24, 2011

Guideline 2b:
The proposed VSL for Requirement R4 does not contain ambiguous
language.

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

VRF and VSL Justifications for R5
Proposed VRF

Lower

NERC VRF Discussion

The proposed VRF is consistent with the NERC definition for lower VRF
because the proposed requirement requires that each Transmission Owner,
Generator Owner, and Distribution Provider that sets transmission line
relays according to Requirement R1 criterion 12 shall provide a list of the
circuits associated with those relays to its Regional Entity at least once each
calendar year, with no more than 15 months between reports. Because the
purpose of the requirement is to share information with other entities
through the exchange of a report the requirement is considered
administrative in nature and consistent with the definition of a lower VRF.
Guideline 1- Consistency w/ Blackout Report
Not applicable. This criterion to which this requirement is related did not
exist at the time of the August 14, 2003 Northeast Blackout.
Guideline 2- Consistency within a Reliability Standard
Requirement R4 has a similar reliability objective and is also assigned a
lower VSL.

FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion

R5
FERC VRF G4
Discussion

FERC VRF G5
Discussion

Proposed Lower VSL

N/A

Proposed Moderate VSL

N/A

Proposed High VSL

N/A

Proposed Severe VSL

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

The proposed VSL for Requirement R5 does not have the unintended
consequence of lowering the current level of compliance because PRC-0231 does not have this requirement as it was added to PRC-023-2.

FERC VSL G2

Guideline 2a:

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
Violation Severity Level
Assignments Should
Ensure Uniformity and
Consistency in the
Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements
Is Not Consistent
Guideline 2b: Violation
Severity Level
Assignments that
Contain Ambiguous
Language

The proposed VSL is binary and was assigned a severe VSL.
Guideline 2b:
The proposed VSL for Requirement R5 does not contain ambiguous
language.

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

The proposed VSL is consistent with the corresponding Requirement, R5.

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

The proposed VSL is based on a single violation and not a cumulative
number of violations.

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

VRF and VSL Justifications for R6
Proposed VRF

High

NERC VRF Discussion
FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion
FERC VRF G4
Discussion

R6
FERC VRF G5
Discussion

Guideline 1- Consistency w/ Blackout Report
A High VRF is consistent with the role that relay loadability played in
contributing to the August 14, 2003 Northeast Blackout. The Blackout
Report identifies examples of sub-200 kV transmission lines tripping due to
relay loadability issues, which resulted in cascading outages of higher
voltage transmission lines.
Guideline 2- Consistency within a Reliability Standard
Not applicable. There are no other requirements in this standard that
address similar reliability goals.
Guideline 3- Consistency among Reliability Standards
Not applicable. There are no other standards that address similar reliability
goals.
Guideline 4- Consistency with NERC Definitions of VRFs
The proposed VRF is consistent with the NERC definitions of VRFs because
as described above the requirement ensures that the Planning Coordinator
will evaluate sub-200 kV circuits to determine which such circuits could,
under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk
electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Circuits thus identified will be subject to the other requirements of PRC023-2.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation
The VRF is consistent with the highest risk reliability objective contained in
this requirement.

Proposed Lower VSL

N/A

Proposed Moderate VSL

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
VRF and VSL Justifications for R6
but provided the list of circuits to the Reliability Coordinators, Transmission
Owners, Generator Owners, and Distribution Providers within its Planning
Coordinator area between 31 days and 45 days after the list was established
or updated. (part 6.2)
Proposed High VSL

Proposed Severe VSL

The Planning Coordinator used the criteria established within Attachment B
at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard and met 6.1 and 6.2
but provided the list of circuits to the Reliability Coordinators, Transmission
Owners, Generator Owners, and Distribution Providers within its Planning
Coordinator area between 46 days and 60 days after list was established or
updated. (part 6.2)
The Planning Coordinator failed to use the criteria established within
Attachment B to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard.
OR
The Planning Coordinator used the criteria established within Attachment
B, at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard but failed to meet
parts 6.1 and 6.2.
OR
The Planning Coordinator used the criteria established within Attachment B
at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard but failed to
maintain the list of circuits determined according to the process described in
Requirement R6. (part 6.1)
OR
The Planning Coordinator used the criteria established within Attachment B
at least once each calendar year, with no more than 15 months between
assessments to determine the circuits in its Planning Coordinator area for
which applicable entities must comply with the standard and met 6.1 but
failed to provide the list of circuits to the Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within
its Planning Coordinator area or provided the list more than 60 days after
the list was established or updated. (part 6.2)

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

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability
VRF and VSL Justifications for R6
Level of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should
Ensure Uniformity and
Consistency in the
Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements
Is Not Consistent
Guideline 2b: Violation
Severity Level
Assignments that
Contain Ambiguous
Language

Guideline 2a:
N/A

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

The proposed VSL is consistent with the corresponding Requirement, R6.

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

The proposed VSL is based on a single violation and not a cumulative
number of violations.

January 24, 2011

Guideline 2b:
The proposed VSL for Requirement R6 does not contain ambiguous
language.

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

NERC’s VRF Criteria:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations,
directly cause or contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability, separation,
or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. However, violation of a medium risk requirement is unlikely, under
emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to bulk electric
system instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected
to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system; or, a requirement that is administrative in nature and a
requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state
or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system. A planning requirement that is administrative in nature.

FERC’s VRF Guidelines:
VRF G1 – Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the reliability of
the Bulk-Power System. From footnote 15 of the May 18, 2007 Order, FERC’s list of critical areas (from
the Final Blackout Report) where violations could severely affect the reliability of the Bulk-Power
System includes:
− Emergency operations
− Vegetation management
− Operator personnel training
− Protection systems and their coordination
− Operating tools and backup facilities
− Reactive power and voltage control
− System modeling and data exchange
− Communication protocol and facilities
− Requirements to determine equipment ratings
− Synchronized data recorders
− Clearer criteria for operationally critical facilities

January 24, 2011

Analysis of Violation Risk Factors and Violation Severity Levels - PRC-023-2 — Transmission
Relay Loadability

−

Appropriate use of transmission loading relief.

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

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

High VSL

Severe VSL

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

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

FERC’s VSL Guidelines:
VSL G1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of
Lowering the Current Level of Compliance (Compare the VSLs to any prior Levels of Noncompliance and avoid significant changes that may encourage a lower level of compliance than was
required when Levels of Non-compliance were used.)
VSL G2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties (A violation of a “binary” type requirement must be a “Severe” VSL. Avoid
using ambiguous terms such as “minor” and “significant” to describe noncompliant performance.)
VSL G3: Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement (VSLs should not expand on what is required in the requirement.)
VSL G4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A
Cumulative Number of Violations (. . . unless otherwise stated in the requirement, each instance of noncompliance with a requirement is a separate violation. Section 4 of the Sanction Guidelines states that
assessing penalties on a per violation per day basis is the “default” for penalty calculations.)

January 24, 2011

Implementation Plan for PRC-023-2 — Transmission Relay Loadability
1. Standards Involved

•

PRC-023-2 —Transmission Relay Loadability

The first day of the first calendar quarter after applicable regulatory approvals, or
in those jurisdictions where no regulatory approval is required, the first calendar
quarter after Board of Trustees adoption, except as noted below.
3.1.1.1.1.
For the addition to Requirement R1, criterion 10, to set transformer fault
protection relays and transmission line relays on transmission lines
terminated only with a transformer such that the protection settings do
not expose the transformer to fault level and duration that exceeds its
mechanical withstand capability, the first day of the first calendar quarter
12 months after applicable regulatory approvals, or in those jurisdictions
where no regulatory approval is required, the first day of the first
calendar quarter 12 months after Board of Trustees adoption.
3.1.1.1.2.
For supervisory elements as described in PRC-023-2 - Attachment A,
Section 1.6, the first day of the first calendar quarter 24 months after
applicable regulatory approvals, or in those jurisdictions where
regulatory approval is not required, the first day of the first calendar
quarter 24 months after Board of Trustees adoption.
3.1.1.1.3.
For switch-on-to-fault schemes as described in PRC-023-2 - Attachment
A, Section 1.3, the later of the first day of the first calendar quarter after
applicable regulatory approvals of PRC-023-2 or the first day of the first
calendar quarter 39 months following applicable regulatory approvals of
PRC-023-1; or in those jurisdictions where no regulatory approval is
required, the later of the first day of the first calendar quarter after Board
of Trustees adoption of PRC-023-2 or July 1, 2011.

3.1.2. For circuits identified by the Planning Coordinator pursuant to Requirement R6
3.1.2.1.

The later of the first day of the first calendar quarter 39 months following
notification by the Planning Coordinator of a circuit’s inclusion on a list of
circuits subject to PRC-023-2 per application of Attachment B, or the first day of
the first calendar year in which any criterion in Attachment B applies.

116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Implementation Plan for RPC-023-2 — Transmission Relay Loadability

3.2. Requirements R2 and R3
3.2.1. For transmission lines operating at 200 kV and above and transformers with low voltage
terminals connected at 200 kV and above.
3.2.1.1.

The first day of the first calendar quarter after applicable regulatory approvals, or
in those jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter after Board of Trustees adoption.

3.2.2. For circuits identified by the Planning Coordinator pursuant to Requirement R6
3.2.2.1.

4.1.1.2.

4.1.1.3.

4.1.1.4.

Transmission Owners with load-responsive phase protection systems as
described in PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1
(Circuits Subject to Requirements R1 – R5).
Generator Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject
to Requirements R1 – R5).
Distribution Providers with load-responsive phase protection systems as
described in PRC-023-2 - Attachment A, applied to circuits defined in
4.2.1(Circuits Subject to Requirements R1 – R5), provided those circuits have bidirectional flow capabilities.
Planning Coordinators

January 24, 2011

Implementation Plan for RPC-023-2 — Transmission Relay Loadability

4.1.2.1.3.

4.1.2.1.4.
4.1.2.1.5.
4.1.2.1.6.

Transmission lines operated below 100 kV that are included on a critical
facilities list defined by the Regional Entity1 and selected by the
Planning Coordinator in accordance with R6
Transformers with low voltage terminals connected at 200 kV and above
Transformers with low voltage terminals connected at 100 kV to 200 kV
selected by the Planning Coordinator
Transformers with low voltage terminals connected below 100 kV that
are included on a critical facilities list defined by the Regional Entity and
selected by the Planning Coordinator

4.1.2.2.
Circuits Subject to Requirement R6
4.1.2.2.1.
Transmission lines operated at 100 kV to 200 kV and transformers with
low voltage terminals connected at 100 kV to 200 kV
4.1.2.2.2.
Transmission lines operated below100 kV and transformers with low
voltage terminals connected below 100 kV that are included on a critical
facilities list defined by the Regional Entity
4.2. Other entities may be recipients of data as described in this standard, but have no requirements
placed upon them
5. Implementation Dates
For circuits already identified and subject to the requirements in PRC-023-1, the existing
implementation dates will remain in effect.
6. Retired Standards
Requirement R1 of PRC-023-1 is retired the first day of the first calendar quarter after applicable
regulatory approvals, or in those jurisdictions where no regulatory approval is required, the first
calendar quarter after Board of Trustees adoption.
Requirement R2 of PRC-023-1 is retired the first day of the first calendar quarter after applicable
regulatory approvals, or in those jurisdictions where no regulatory approval is required, the first day
of the first calendar quarter after Board of Trustees adoption.
Requirement R3 of PRC-023-1 is retired the first day of the first calendar quarter 18 months after
applicable regulatory approvals, or in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
When all requirements of PRC-023-2 become effective in all jurisdictions as specified above, PRC023-1 — Transmission Relay Loadability will be retired.

If the Regional Entity has developed such a list.

January 24, 2011

Implementation Plan for PRC-023-2: — Transmission Relay Loadability
1. Standards Involved

•

• PRC-023-2 —Transmission Relay Loadability

2. Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before the Transmission Relay Loadability standard can be
implemented.
3. Proposed Effective Date Dates
3.1. Requirement R1: the
3.1.1. For transmission lines operating at 200 kV and above and transformers with low voltage
terminals connected at 200 kV and above
2.1.1.1.3.1.1.1. The first day of the first calendar quarter after applicable regulatory
approvals, or in those jurisdictions where no regulatory approval is required, the
first calendar quarter after Board of Trustees adoption, except as noted below.
2.1.1.1.1.3.1.1.1.1. For the addition to Requirement R1, criterion 10, to set
transformer fault protection relays and transmission line relays on
transmission lines terminated only with a transformer such that the
protection settings do not expose the transformer to fault level and
duration that exceeds its mechanical withstand capability, the first day of
the first calendar quarter 12 months after applicable regulatory approvals,
or in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter 12 months after Board of Trustees
adoption.
2.1.1.1.2.3.1.1.1.2. For supervisory elements as described in PRC-023-2 Attachment A, sectionSection 1.6, the first day of the first calendar
quarter 24 months after applicable regulatory approvals, or in those
jurisdictions where no regulatory approval is not required, the first day of
the first calendar quarter 24 months after Board of Trustees adoption.
3.1.1.1.3.

Requirements R2 and R3:For switch-on-to-fault schemes as described in
PRC-023-2 - Attachment A, Section 1.3, the later of the first day of the
first calendar quarter after applicable regulatory approvals of PRC-023-2
or the first day of the first calendar quarter 39 months following
applicable regulatory approval of PRC-023-1; or in those jurisdictions
where no regulatory approval is required, the later of the first day of the
first calendar quarter after Board of Trustees adoption of PRC-023-2 or
July 1, 2011.

3.1.2. For circuits identified by the Planning Coordinator pursuant to Requirement R6
3.1.2.1.

The later of the first day of the first calendar quarter 39 months following
notification by the Planning Coordinator of a circuit’s inclusion on a list of
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Implementation Plan for PRCRPC-023-2: — Transmission Relay Loadability

circuits subject to PRC-023-2 per application of Attachment B, or the first day of
the first calendar year in which any criterion in Attachment B applies.
3.2. Requirements R2 and R3
3.2.1. For transmission lines operating at 200 kV and above and transformers with low voltage
terminals connected at 200 kV and above.
2.1.1.2.3.2.1.1. The first day of the first calendar quarter after applicable regulatory
approvals, or in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter after Board of Trustees adoption.
3.2.2. For circuits identified by the Planning Coordinator pursuant to Requirement R6
3.2.2.1.

3.3. Requirements R4 and R5: the
The first day of the first calendar quarter six months after applicable regulatory approvals, or in
those jurisdictions where no regulatory approval is required, the first day of the first calendar
quarter six months after Board of Trustees adoption.
3.4. Requirement R6: the
The first day of the first calendar quarter 18 months after applicable regulatory approvals or in those
jurisdictions where no regulatory approval is required the first day of the first calendar quarter 18 months
after Board of Trustees adoption.
Requirement R7: the first day of the first calendar quarter after applicable regulatory approvals,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter 18 months after Board of Trustees adoption.
3.4.

Applicability

3.1.4.1.

Requirements within the proposed standard apply to: the following:

3.1.1.4.1.1.

4.1.

Functional Entities:Entity

3.1.1.1.4.1.1.1. 4.1.1 Transmission Owners with load-responsive phase protection
systems as described in PRC-023-2 - Attachment A, applied to facilitiescircuits
defined in 4.2.1 through 4.2.6.(Circuits Subject to Requirements R1 – R5).
3.1.1.2.4.1.1.2. 4.1.2 Generator Owners with load-responsive phase protection
systems as described in PRC-023-2 - Attachment A, applied to facilitiescircuits
defined in 4.2.1 through 4.2.6.(Circuits Subject to Requirements R1 – R5).
3.1.1.3.4.1.1.3. 4.1.3 Distribution Providers with load-responsive phase protection
systems as described in PRC-023-2 - Attachment A, applied according to
facilitiescircuits defined in 4.2.1 through 4.2.6,(Circuits Subject to Requirements
R1 – R5), provided those facilitiescircuits have bi-directional flow capabilities.
3.1.1.4.4.1.1.4.

4.1.4

Planning Coordinators

November 1, 2010January 24, 2011

Implementation Plan for PRCRPC-023-2: — Transmission Relay Loadability

4.2.

Facilities:

4.1.2. 4.2.1

Circuits

4.1.2.1.
Circuits Subject to Requirements R1 – R5
3.1.1.4.1.4.1.2.1.1. Transmission lines operated at 200 kV and above.
3.1.1.4.2.4.1.2.1.2. 4.2.2 Transmission lines operated at 100 kV to 200 kV
thatselected by the Planning Coordinator has determined are required to
comply with this standard.
3.1.1.4.3.4.1.2.1.3. 4.2.3 Transmission lines operated below 100 kV that Regional
Entities have identified asare included on a critical facilities for the
purposes oflist defined by the Compliance RegistryRegional Entity 1 and
selected by the Planning Coordinator has determined are required to
comply with this standard. in accordance with R6
3.1.1.4.4.4.1.2.1.4. 4.2.4 Transformers with low voltage terminals connected at
200 kV and above.
3.1.1.4.5.4.1.2.1.5. 4.2.5 Transformers with low voltage terminals connected at
100 kV to 200 kV thatselected by the Planning Coordinator has
determined are required to comply with this standard.
3.1.1.4.6.4.1.2.1.6. 4.2.6 Transformers with low voltage terminals connected
below 100 kV that Regional Entities have identified asare included on a
critical facilities forlist defined by the purposes of the Compliance
RegistryRegional Entity and selected by the Planning Coordinator has
determined are required to comply with this standard
4.1.2.2.
Circuits Subject to Requirement R6
4.1.2.2.1.
Transmission lines operated at 100 kV to 200 kV and transformers with
low voltage terminals connected at 100 kV to 200 kV
4.1.2.2.2.
Transmission lines operated below100 kV and transformers with low
voltage terminals connected below 100 kV that are included on a critical
facilities list defined by the Regional Entity
3.2.4.2.
Other entities may be recipients of data as described in this standard, but have no
requirements placed upon them.
5. Implementation Dates
For circuits already identified and subject to the requirements in PRC-023-1, the existing
implementation dates will remain in effect.
4.6.
Retired Standards
The following standard will be retired when PRC-023-2 becomes effective:
•

If the Regional Entity has developed such a list.

November 1, 2010January 24, 2011

Implementation Plan for PRCRPC-023-2: — Transmission Relay Loadability

Requirement R1 of PRC-023-1 is retired the first day of the first calendar quarter after applicable
regulatory approval, or in those jurisdictions where no regulatory approval is required, the first
calendar quarter after Board of Trustees adoption.
Requirement R2 of PRC-023-1 is retired the first day of the first calendar quarter after applicable
regulatory approval, or in those jurisdictions where no regulatory approval is required, the first day of
the first calendar quarter after Board of Trustees adoption.
Requirement R3 of PRC-023-1 is retired the first day of the first calendar quarter 18 months after
applicable regulatory approval, or in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter 18 months after Board of Trustees adoption.
When all requirements of PRC-023-2 become effective in all jurisdictions as specified above, PRC023-1 — Transmission Relay Loadability will be completely retired once PRC-023-2 becomes
effective as specified above. retired.

November 1, 2010January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on August 12, 2010.
2. SAR posted for formal comment on August 19, 2010.
3. Standard posted for informal comment period on August 19, 2010.
4. Attachment B (Applicability Test) of standard posted for informal comment period on September
23, 2010.
5. Standard with applicability test posted for 45-day formal comment period with concurrent ballot
during the last 10 days of the comment period on November 1, 2010.
Proposed Action Plan and Description of Current Draft:
This is the third draft of the standard developed to address the FERC directives in Order No. 733 and is
posted for a 20-day successive ballot period.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Develop third draft of the standard and respond to comments

December 2010 –
January 2011

2. Conduct successive ballot and recirculation ballot of standard

January 2011February 2011

3. Submit to NERC Board of Trustees for approval to file

February 2011

4. File standard with FERC for approval

March 2011

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-2

3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with
system operators’ ability to take remedial action to protect system reliability and; be set to
reliably detect all fault conditions and protect the electrical network from these faults.
4. Applicability
4.1. Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.2 Generator Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.3 Distribution Providers with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1(Circuits Subject to
Requirements R1 – R5), provided those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinators
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.2.1.1 Transmission lines operated at 200 kV and above.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning
Coordinator.
4.2.1.3 Transmission lines operated below 100 kV that are included on a critical
facilities list defined by the Regional Entity 1 and selected by the Planning
Coordinator in accordance with R6.
4.2.1.4 Transformers with low voltage terminals connected at 200 kV and above.
4.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV
selected by the Planning Coordinator.
4.2.1.6 Transformers with low voltage terminals connected below 100 kV that are
included on a critical facilities list defined by the Regional Entity and selected
by the Planning Coordinator in accordance with R6.
4.2.2 Circuits Subject to Requirement R6
4.2.2.1 Transmission lines operated at 100 kV to 200 kV and transformers with low
voltage terminals connected at 100 kV to 200 kV

If the Regional Entity has developed such a list.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
4.2.2.2 Transmission lines operated below100 kV and transformers with low voltage
terminals connected below 100 kV that are included on a critical facilities list
defined by the Regional Entity
5.

Effective Dates
5.1. Requirement R1
5.1.1 For transmission lines operating at 200 kV and above and transformers with low
voltage terminals connected at 200 kV and above.
5.1.1.1 The first day of the first calendar quarter after applicable regulatory approval or
in those jurisdictions where no regulatory approval is required, the first
calendar quarter after Board of Trustees adoption, except as noted below.
5.1.1.1.1

For the addition to Requirement R1, criterion 10, to set transformer fault
protection relays and transmission line relays on transmission lines
terminated only with a transformer such that the protection settings do
not expose the transformer to fault level and duration that exceeds its
mechanical withstand capability, the first day of the first calendar quarter
12 months after applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, the first day of the first
calendar quarter 12 months after Board of Trustees adoption.

5.1.1.1.2

For supervisory elements as described in PRC-023-2 - Attachment A,
Section 1.6, the first day of the first calendar quarter 24 months after
applicable regulatory approvals, or in those jurisdictions where
regulatory approval is not required, the first day of the first calendar
quarter 24 months after Board of Trustees adoption.

5.1.1.1.3

For switch-on-to-fault schemes as described in PRC-023-2 - Attachment
A, Section 1.3, the later of the first day of the first calendar quarter after
applicable regulatory approval of PRC-023-2 or the first day of the first
calendar quarter 39 months following applicable regulatory approval of
PRC-023-1; or in those jurisdictions where no regulatory approval is
required, the later of the first day of the first calendar quarter after Board
of Trustees adoption of PRC-023-2 or July 1, 2011.

5.1.2 For circuits identified by the Planning Coordinator pursuant to Requirement R6
5.1.2.1 The later of the first day of the first calendar quarter 39 months following
notification by the Planning Coordinator of a circuit’s inclusion on a list of
circuits subject to PRC-023-2 per application of Attachment B, or the first day
of the first calendar year in which any criterion in Attachment B applies.
5.2. Requirements R2 and R3
5.2.1 For transmission lines operating at 200 kV and above and transformers with low
voltage terminals connected at 200 kV and above.
5.2.1.1 The first day of the first calendar quarter after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day
of the first calendar quarter after Board of Trustees adoption.
5.2.2 For circuits identified by the Planning Coordinator pursuant to Requirement R6
5.2.2.1 The later of the first day of the first calendar quarter 39 months following
notification by the Planning Coordinator of a circuit’s inclusion on a list of

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
circuits subject to PRC-023-2 per application of Attachment B, or the first day
of the first calendar year in which any criterion in Attachment B applies.
5.3. Requirements R4 and R5
The first day of the first calendar quarter six months after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter six months after Board of Trustees adoption.
5.4. Requirement R6
The first day of the first calendar quarter 18 months after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter 18 months after Board of Trustees adoption.
B. Requirements
R1.

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at each
end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate
at or below the maximum power transfer capability of the line, determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with Requirement R1, criterion 3, using the full
line inductive reactance.

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
5. Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes).
6. Set transmission line relays applied on transmission lines connected to generation stations
remote to load so they do not operate at or below 230% of the aggregated generation
nameplate capability.
7. Set transmission line relays applied at the load center terminal, remote from generation
stations, so they do not operate at or below 115% of the maximum current flow from the
load to the generation source under any system configuration.
8. Set transmission line relays applied on the bulk system-end of transmission lines that serve
load remote to the system so they do not operate at or below 115% of the maximum current
flow from the system to the load under any system configuration.
9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the load to the system under any system configuration.
10. Set transformer fault protection relays and transmission line relays on transmission lines
terminated only with a transformer so that the relays do not operate at or below the greater
of:
•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

•

115% of the highest operator established emergency transformer rating

10.1

11. For transformer overload protection relays that do not comply with the loadability
component of Requirement R1, criterion 10 set the relays according to one of the
following:
•

•

As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer
Through-Fault-Current Duration, Clause 4.4, Figure 4
4

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.
b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
c. Include a relay setting component of 87% of the current calculated in Requirement
R1, criterion 12 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

R3.

R4.

R5.

R6.

Maintain a list of circuits subject to PRC-023-2 per application of Attachment B,
including identification of the first calendar year in which any criterion in Attachment B
applies.

6.2

Provide the list of circuits to all Regional Entities, Reliability Coordinators, Transmission
Owners, Generator Owners, and Distribution Providers within its Planning Coordinator

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
area within 30 calendar days of the establishment of the initial list and within 30 calendar
days of any changes to that list.
C. Measures
M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as spreadsheets or summaries of calculations to show that each of its transmission relays
is set according to one of the criteria in Requirement R1, criterion 1 through 13 and shall have
evidence such as coordination curves or summaries of calculations that show that relays set per
criterion 10 do not expose the transformer to fault levels and durations beyond those indicated
in the standard. (R1)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking
elements is set to allow tripping of phase protective relays for faults that occur during the
loading conditions used to verify transmission line relay loadability per Requirement R1. (R2)
M3. Each Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence such
as Facility Rating spreadsheets or Facility Rating database to show that it used the calculated
circuit capability as the Facility Rating of the circuit and evidence such as dated
correspondence that the resulting Facility Rating was agreed to by its associated Planning
Coordinator, Transmission Operator, and Reliability Coordinator. (R3)
M4. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 2 shall have evidence such as dated
correspondence to show that it provided its Planning Coordinator, Transmission Operator, and
Reliability Coordinator with an updated list of circuits associated with those transmission line
relays within the required timeframe. The updated list may either be a full list or a list of
incremental changes to the previous list. (R4)
M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided an updated list of the circuits associated with those relays to its
Regional Entity within the required timeframe. The updated list may either be a full list or a
list of incremental changes to the previous list. (R5)
M6. Each Planning Coordinator shall have evidence such as power flow results, calculation
summaries, or study reports that it used the criteria established within Attachment B to
determine the circuits in its Planning Coordinator area for which applicable entities must
comply with the standard as described in Requirement R6. The Planning Coordinator shall
have a dated list of such circuits and shall have evidence such as dated correspondence that it
provided the list to the Regional Entities, Reliability Coordinators, Transmission Owners,
Generator Owners, and Distribution Providers within its Planning Coordinator area within the
required timeframe. (R6)

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
•

•

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
None.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

Violation Severity Levels:

Requirement
R1

Lower
N/A

Moderate
N/A

High
N/A

N/A

The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that
occur during the loading
conditions used to verify
transmission line relay loadability
per Requirement R1.

N/A

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with an
updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

The responsible entity did not
provide its Regional Entity, with
an updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 12 at least once each
calendar year, with no more than
15 months between reports.

N/A

Draft 3: January 21, 2011

OR
The Planning Coordinator used the
criteria established within
Attachment B, at least once each

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate
OR

OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 and 6.2 but provided the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area
between 31 days and 45 days after
the list was established or updated.
(part 6.2)

Draft 3: January 21, 2011

High

Severe
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to meet parts 6.1 and 6.2.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to maintain the list of
circuits determined according to
the process described in
Requirement R6. (part 6.1)
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 but failed to provide the list of
circuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator area or

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
provided the list more than 60 days
after the list was established or
updated. (part 6.2)

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.
Version History
Version

Date

Action

Change Tracking

February 12, 2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe VSL Errata
for Requirement 3 — “then” should be “than.”

March 18, 2010

Approved by FERC

November 1, 2010

Revised to address directives from Order 733

January 14, 2011

Revised to address formal industry comments

Draft 3: January 21, 2011

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

1.6. Supervisory elements associated with current-based, communication-assisted schemes where
the scheme is capable of tripping for loss of communications.
2. The following protection systems are excluded from requirements of this standard:
2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications except as noted in
section 1.6

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
PRC-023 — Attachment B
Circuits to Evaluate

•
•

Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals
connected at 100 kV to 200 kV.
Lines operated below100 kV and transformers with low voltage terminals connected below 100
kV that are included on a critical facilities list defined by the Regional Entity.

Criteria
If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for
that circuit.
B1. The circuit is a monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Québec Interconnection, that has been included to address
reliability concerns for loading of that circuit, as confirmed by the applicable Planning
Coordinator.
B2. The circuit is a monitored Facility of an IROL, where the IROL was determined in the planning
horizon pursuant to FAC-010.
B3. The circuit forms a path (as agreed to by the plant owner and the transmission entity) to supply
off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements
(NPIRs) pursuant to NUC-001.
B4. The circuit is identified through the following sequence of power flow analyses 5 performed by the
Planning Coordinator for the one-to-five-year planning horizon:
a. Simulate double contingency combinations selected by engineering judgment, without
manual system adjustments in between the two contingencies (reflects a situation where a
System Operator may not have time between the two contingencies to make appropriate
system adjustments).
b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in
consultation with the Facility owner, against a threshold based on the Facility Rating assigned
for that circuit and used in the power flow case by the Planning Coordinator.
c. When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.
d. The threshold for selection of the circuit will vary based on the loading duration assumed in
the development of the Facility Rating.

Past analyses may be used to support the assessment if no material changes to the system have occurred since the
last assessment

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
i.

If the Facility Rating is based on a loading duration of up to and including four hours,
the circuit must comply with the standard if the loading exceeds 115% of the Facility
Rating.

ii.

iii.

If the Facility Rating is based on a loading duration of greater than eight hours, the
circuit must comply with the standard if the loading exceeds 130% of the Facility
Rating.

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on August 12, 2010.
2. SAR posted for formal comment on August 19, 2010.
3. Standard posted for informal comment period on August 19, 2010.
4. Attachment B (Applicability Test) of standard posted for informal comment period on September
23, 2010.
5. Standard with applicability test posted for 45-day formal comment period with concurrent ballot
during the last 10 days of the comment period on November 1, 2010.
Proposed Action Plan and Description of Current Draft:
This is the secondthird draft of the standard developed to address the FERC directives in Order No. 733
and is posted for a 4520-day formal comment period with concurrentsuccessive ballot during the last 10
days of the comment period.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Develop third draft of the standard and respond to comments.

December 2010 –
January 2011

2. Conduct successive ballot and recirculation ballot of standard

January 2011February 2011

3. Submit to NERC Board of Trustees for approval to file

February 2011

4. SubmitFile standard towith FERC for approval

March 2011

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-2

FERC Order 733, ¶60: Apply

an “add in” approach to sub4.2.1.3 Transmission lines operated below 100 kV that
100 kV facilities.
Regional Entities have identified asare included on
a critical facilities forlist defined by the purposes of
the Compliance RegistryRegional Entity 1 and selected by the Planning
Coordinator has determined are required to comply with this standardin
accordance with R6.

4.2.1.4 Transformers with low voltage terminals connected at 200 kV and above.
4.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV
thatselected by the Planning Coordinator has determined are required to
comply with this standard.

If the Regional Entity has developed such a list.

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
4.2.1.6 Transformers with low voltage terminals connected below 100 kV that
Regional Entities have identified asare included on a critical facilities forlist
defined by the purposes of the Compliance Registry Regional Entity and
selected by the Planning Coordinator has
determined are required to complyin accordance
FERC Order 733, ¶284:
with this standardR6.
Remove the exceptions
4.2.2 Circuits Subject to Requirement R6

footnote from the “Effective
Dates” section.

4.2.2.1 Transmission lines operated at 100 kV to 200 kV
and transformers with low voltage terminals connected at 100 kV to 200 kV
4.2.2.2 Transmission lines operated below100 kV and transformers with low voltage
terminals connected below 100 kV that are included on a critical facilities list
defined by the Regional Entity
5.

Effective Dates:
5.1. Requirement R1: the
5.1.1 For transmission lines operating at 200 kV and above and transformers with low
voltage terminals connected at 200 kV and above.
5.1.1.1 The first day of the first calendar quarter after applicable regulatory
approvalsapproval or in those jurisdictions where no regulatory approval is
required, the first calendar quarter after Board of Trustees adoption, except as
noted below.
5.1.1.1.1

For the addition to Requirement R1, criterion 10, to set transformer fault
protection relays and transmission line relays on transmission lines
terminated only with a transformer such that the protection settings do
not expose the transformer to fault level and duration that exceeds its
mechanical withstand capability, the first day of the first calendar quarter
12 months after applicable regulatory approvalsapproval, or in those
jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter 12 months after Board of Trustees adoption.

5.1.1.1.2

For supervisory elements as described in PRC-023-2 - Attachment A,
sectionSection 1.6, the first day of the first calendar quarter 24 months
after applicable regulatory approvals, or in those jurisdictions where
regulatory approval is not required, the first day of the first calendar
quarter 24 months after Board of Trustees adoption.

5.1.1.1.3

Requirements R2 and R3:For switch-on-to-fault schemes as described in
PRC-023-2 - Attachment A, Section 1.3, the later of the first day of the
first calendar quarter after applicable regulatory approvalsapproval of
PRC-023-2 or the first day of the first calendar quarter 39 months
following applicable regulatory approval of PRC-023-1; or in those
jurisdictions where no regulatory approval is required, the later of the
first day of the first calendar quarter after Board of Trustees adoption of
PRC-023-2 or July 1, 2011.

5.1.2 Requirements R4 and R5: the first day of the first calendar quarter six months after
applicable regulatory approvals or in those jurisdictions where no regulatory approval
is required the first For circuits identified by the Planning Coordinator pursuant to
Requirement R6

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
5.2. The later of the first day of the first calendar quarter six39 months after Board of Trustees
adoption.
5.2.1.15.1.2.1 Requirement R6:following notification by the Planning Coordinator of a
circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of
Attachment B, or the first day of the first calendar quarter 18 months after
applicable regulatory approvals or in those jurisdictions where no regulatory
approval is required the first day of the first calendar quarter 18 months after
Board of Trustees adoption. year in which any criterion in Attachment B
applies.
5.2. Requirement R7: theRequirements R2 and R3
5.2.1 For transmission lines operating at 200 kV and above and transformers with low
voltage terminals connected at 200 kV and above.
5.2.1.25.2.1.1 The first day of the first calendar quarter after applicable regulatory
approvalsapproval, or in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter after Board of Trustees
adoption.
5.2.2 For circuits identified by the Planning Coordinator pursuant to Requirement R6
5.2.2.1 The later of the first day of the first calendar quarter 39 months following
notification by the Planning Coordinator of a circuit’s inclusion on a list of
circuits subject to PRC-023-2 per application of Attachment B, or the first day
of the first calendar year in which any criterion in Attachment B applies.
5.3. Requirements R4 and R5
The first day of the first calendar quarter six months after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter six months after Board of Trustees adoption.
5.4. Requirement R6
The first day of the first calendar quarter 18 months after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter 18 months after Board of Trustees adoption.
B. Requirements
R1.

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal
15-minute Facility Rating2 of a circuit (expressed in amperes).
3. Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:
•

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at each
end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate
at or below the maximum power transfer capability of the line, determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with Requirement R1, criterion 3, using the full
line inductive reactance.

5. Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes).
6. Set transmission line relays applied on transmission lines connected to generation stations
remote to load so they do not operate at or below 230% of the aggregated generation
nameplate capability.
7. Set transmission line relays applied at the load center terminal, remote from generation
stations, so they do not operate at or below 115% of the maximum current flow from the
load to the generation source under any system configuration.
8. Set transmission line relays applied on the bulk system-end of transmission lines that serve
load remote to the system so they do not operate at or below 115% of the maximum current
flow from the system to the load under any system configuration.
9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the load to the system under any system
configuration.
FERC Order 733, ¶203: Modify
10. Set transformer fault protection relays and transmission line
relays on transmission lines terminated only with a
transformer such that the protection settings do not expose
the transformer to fault level and duration that exceeds its
mechanical withstand capability and so that the relays do
not operate at or below the greater of:

sub-requirement R1.10 to verify
equipment is capable of
sustaining the anticipated
overload associated with the
fault.

When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

•

115% of the highest operator established emergency transformer rating.

10.1

11. For transformer overload protection relays that do not comply with the loadability
component of Requirement R1, criterion 10 set the relays according to one of the
following:
•

•

12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.
b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
c. Include a relay setting component of 87% of the current calculated in Requirement
R1, criterion 12 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

Each Transmission Owner, Generator Owner, and
FERC Order 733, ¶244: Include
Distribution Provider shall verify thatset its out-of-step
section 2 of Appendix A as an
blocking elements to allow tripping of phase protective
additional Requirement.
relays for faults that occur during the loading conditions
used to verify transmission line relay loadability per
Requirement R1. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer
Through-Fault-Current Duration, Clause 4.4, Figure 4
4

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
R3.

R4.

FERC Order 733, ¶186: Modify
Each Transmission Owner, Generator Owner, and
R1.2 to require that TOs, GOs,
Distribution Provider that chooses to use Requirement R1
and DPs give their TOPs a list of
criterion 2 as the basis for verifying transmission line relay
transmission facilities that
loadability shall provide its Planning Coordinator,
implement R1.2.
Transmission Operator, and Reliability Coordinator with
aan updated list of facilitiescircuits associated with those transmission line relays at least once
each calendar year, with no more than 15 months between reports. [Violation Risk Factor:
Lower] [Time Horizon: Long Term Planning]

R5.

Each Transmission Owner, Generator Owner, and
Distribution Provider that sets transmission line relays
according to Requirement R1 criterion 12 shall provide aan
updated list of the facilitiescircuits associated with those
relays to its Regional Entity at least once each calendar year,
with no more than 15 months between reports, to allow
entitiesthe ERO to know which facilities compile a list of all
circuits that have protective relay settings that limit the
facility’scircuit capability. [Violation Risk Factor: Lower]
[Time Horizon: Long Term Planning]

R6.

Each Planning Coordinator shall apply the criteria in Attachment B to conduct an assessment
conducted at least once each calendar year, with no more than 15 months between assessments,
to by applying the criteria in Attachment B to determine the circuits in its Planning Coordinator
area for which transmission ElementsTransmission Owners, Generator Owners, and
Distribution Providers must comply with this standard.Requirements R1 through R5. The
Planning Coordinator shall: [Violation Risk Factor: High] [Time Horizon: Long Term
Planning]

6.1

Apply the criteria to transmission lines that are operated at 100 kV to 200 kV and
transformers with low voltage terminals connected at 100 kV to 200 kV.

6.2

6.3

Maintain a list of facilities determined according to the
process described in Requirement R6.

6.46.1
Include on the list thecircuits subject to PRC023-2 per application of Attachment B, including
identification of the first calendar year studied forin which
any criterion B4 in Attachment B first applies when a
facility is added and only criterion B4 is applicableapplies.

FERC Order 733, ¶237:
Modify sub-requirement
R3.3 to add the RE to
list of entities that
receive the critical
facilities list.

6.56.2
Provide athe list of facilitiescircuits to all Regional Entities, Reliability
Coordinators, Transmission Owners, Generator Owners, and Distribution Providers

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
within its Planning Coordinator Areaarea within 30 calendar days of the establishment of
the initial list and within 30 calendar days of any changes to that list.
R7.

C. Measures
M1. TheEach Transmission Owner, Generator Owner, and Distribution Provider shall have
evidence such as spreadsheets or summaries of calculations to show that each of its
transmission relays is set according to one of the criteria in Requirement R1, criterion 1
through 13 and shall have evidence such as coordination curves or summaries of calculations
that show that relays set per criterion 10 do not expose the transformer to fault levels and
durations beyond those indicated in the standard. (R1)
M2. TheEach Transmission Owner, Generator Owner, and Distribution Provider shall have
evidence such as spreadsheets or summaries of calculations to show that each of its out-of-step
blocking elements allowsis set to allow tripping of phase protective relays for faults that occur
during the loading conditions used to verify transmission line relay loadability per Requirement
R1. (R2)
M3. TheEach Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence such
as Facility Rating spreadsheets or Facility Rating database to show that theyit used the
calculated circuit capability as the Facility Rating of the circuit and evidence such as dated
correspondence that the resulting Facility Rating was agreed to by its associated Planning
Coordinator, Transmission Operator, and Reliability Coordinator. (R3)
M4. TheEach Transmission Owner, Generator Owner, or Distribution Provider that sets
transmission line relays according to Requirement R1, criterion 2 shall have evidence such as
dated correspondence to show that theyit provided its Planning Coordinator, Transmission
Operator, and Reliability Coordinator with aan updated list of facilitiescircuits associated with
those transmission line relays within the required timeframe. The updated list may either be a
full list or a list of incremental changes to the previous list. (R4)
M5. TheEach Transmission Owner, Generator Owner, or Distribution Provider that sets
transmission line relays according to Requirement R1, criterion 12 shall have evidence such as
dated correspondence that it provided aan updated list of the facilitiescircuits associated with
those relays to its Regional Entity within the required timeframe. The updated list may either
be a full list or a list of incremental changes to the previous list. (R5)
M6. TheEach Planning Coordinator shall have evidence such as power flow results, calculation
summaries, or study reports that theyit used the criteria established within Attachment B to
determine the facilities thatcircuits in its Planning Coordinator area for which applicable
entities must comply with thisthe standard as described in Requirement R6. The Planning
Coordinator shall have a dated list of such facilitiescircuits and shall have evidence such as
dated correspondence that it provided the list to the Regional Entities, Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within its Planning
Coordinator Area. area within the required timeframe. (R6)
Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

M7. The Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
such as dated spreadsheets, summaries of calculations, and study reports, that it implemented
the Requirements within the specified timeframe per Requirement R7.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity
•

•

1.2. Data Retention
The Transmission Owner, Generator Owner, Distribution Provider and Planning Coordinator
shall keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation to demonstrate compliance with Requirements R1 through R5 and R7 for
three calendar years.
The Planning Coordinator shall retain documentation of the most recent review process
required in R6. The Planning Coordinator shall retain the most recent list of facilities that are
critical to the reliability of the electric systemcircuits in its Planning Coordinator area for
which applicable entities must comply with the standard, as determined per R6.
If a Transmission Owner, Generator Owner, Distribution Provider or Planning Coordinator is
found non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time specified above, whichever is longer.
The Compliance Monitor shall keep the last audit record and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
•

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

1.4. Additional Compliance Information
None.

Draft 2: November 1, 20103: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

Violation Severity Levels:

Requirement
R1

Lower
N/A

Moderate
N/A

High
N/A

N/A

The responsible entity failed to
ensure that its out-of-step blocking
elements allowed tripping of phase
protective relays for faults that
occur during the loading
conditions used to verify
transmission line relay loadability
per Requirement R1.

N/A

Draft 2: November 1, 20103: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, Regional
Entity, and Reliability Coordinator
with aan updated list of
facilitiescircuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

The responsible entity did not
provide its Regional Entity, with
aan updated list of facilitiescircuits
that have transmission line relays
set according to the criteria
established in Requirement R1
criterion 12 at least once each
calendar year, with no more than
15 months between reports.

N/A

The Planning Coordinator used the
criteria established within
Attachment B to determine which
transmission Elements, described
in 6.1 and 6.2,the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
parts 6.3 through1 and 6.52, but
more than 15 months and less than

The Planning Coordinator failed to
use the criteria established within
Attachment B to determine which
transmission Elements, described
in 6.1 and 6.2,the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard.

Draft 2: November 1, 20103: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate
24 months lapsed between
assessments.
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and
6.2,the circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.31 and
6.52 but failed to include the
calendar year studied forin which
any criterion B4 in Attachment B
first applies when a facility is
added and only criterion B4 is
applicable (part 6.4)..
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and
6.2,the circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.31 and
6.42 but provided the list of
facilitiescircuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and

Draft 2: November 1, 20103: January 21, 2011

High
assessments.

OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and
6.2,the circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.31 and
6.42 but provided the list of
facilitiescircuits to the Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers within its
Planning Coordinator Area
withinarea between 46 days and 60
days after list was established or
updated. (part 6.5).2)

Severe
The Planning Coordinator used the
criteria established within
Attachment B, at least once each
calendar year, with no more than
15 months between assessments,
to determine which transmission
Elements, described in 6.1 and
6.2,the circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard but failed to
meet parts 6.3, 6.41 and 6.52.
OR
The Planning Coordinator used the
criteria established within
Attachment B, at least once each
calendar year, with no more than
15 months between assessments,
to determine which transmission
Elementsthe circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to apply the criteriamaintain
the list of circuits determined
according to the Elementsprocess
described in partsRequirement R6.
(part 6.1 and 6.2. )
OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and
6.2,the circuits in its Planning

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Distribution Providers within its
Planning Coordinator Area within
31days area between 31 days and
45 days after the list was
established or updated. (part
6.5).2)

N/A

Draft 2: November 1, 20103: January 21, 2011

N/A

Severe
Coordinator area for which
applicable entities must comply
with the standard and met 6.4 and
6.5 but failed to maintain the list of
facilities determined according to
the process described in
Requirement R6 (part 6.3).

N/A

OR
The Planning Coordinator used the
criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments to
determine which transmission
Elements, described in 6.1 and 6.2,
in its Planning Coordinator area
must comply with the standard and
met 6.3 and 6.41 but failed to
provide the list of facilitiescircuits
to the Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution
Providers within its Planning
Coordinator Area area or provided
the list more than 60 days after the
list was established or updated.
(part 6.5).2)
The Transmission Owner,
Generator Owner, or Distribution
Provider failed to implement
Requirement R1, Requirement R2,
Requirement R3, Requirement R4,
and Requirement R5 for each
facility that is added to the
Planning Coordinator’s list of
facilities that must comply with
this standard pursuant to
Requirement R6, Part 6.5 by the

Standard PRC-023-2 — Transmission Relay Loadability
Requirement

Lower

Moderate

High

Severe
later of the first day of the second
calendar quarter after 24 months
following notification by the
Planning Coordinator of a
facility’s inclusion on such a list
by the Planning Coordinator or the
first day of the first calendar
quarter of the year in which
Attachment B criterion B4 first
applies.

Draft 2: November 1, 20103: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.
Version History
Version

Date

Action

Change Tracking

February 12, 2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe VSL Errata
for Requirement 3 — “then” should be “than.”

March 18, 2010

Approved by FERC

November 1, 2010

Revised to address directives from Order 733

January 14, 2011

Revised to address formal industry comments

Draft 2: November 1, 20103: January 21, 2011

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

1.6. Supervisory elements associated with current-based,
communication-assisted schemes where the scheme is capable of
tripping for loss of communications.

FERC Order 733, ¶264: Revise
section 1 of Attachment A to
include supervising relay
elements.

2. The following protection systems are excluded from requirements of
this standard:
2.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications except as noted in
section 1.6

Draft 2: November 1, 20103: January 21, 2011

FERC Order 733, ¶69: Specify
the test that PCs must use to
determine whether sub-200 kV
facility is critical to reliability of
the BES

Circuits to Evaluate

•
•

Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals
connected at 100 kV to 200 kV.
Transmission linesLines operated below100 kV and transformers with low voltage terminals
connected below 100 kV that Regional Entities have identified as are included on a critical
facilities for list defined by the purposes of the Compliance RegistryRegional Entity.

Criteria
If any of the following criteria apply to a circuit, the circuitapplicable entity must comply with the
standard for that circuit.
B1. EachThe circuit that is a monitored ElementFacility of a permanent flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the
Regional Entity, or a comparable monitored ElementFacility in the Texas Interconnection or
Québec Interconnection, that has been included to address long-term reliability concerns for
loading of that circuit, as confirmed by the applicable Planning Coordinator.
B2. EachThe circuit that is a monitored ElementFacility of an IROL, where the IROL was determined
in the long-term planning horizon pursuant to FAC-010.
B3. EachThe circuit that forms a path (as agreed to by the plant owner and the Transmission
Entitytransmission entity) to supply off-site power to a nuclear plants. plant as established in the
Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001.
B4. EachThe circuit is identified through the following sequence of power flow analysisanalyses 5
performed by the Planning Coordinator for the one-to-five-year planning horizon:
a. Simulate double contingency combinations selected by engineering judgment in TPL-003
Category C3, but, without manual system adjustments in between the two contingencies
(reflects a situation where a System Operator may not have time between the two
contingencies to make appropriate system adjustments).
b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in
consultation with the Facility owner, against a threshold based on the Facility Rating assigned
for that circuit and used in the power flow case by the Planning Coordinator.

Past analyses may be used to support the assessment if no material changes to the system have occurred since the
last assessment

Draft 2: November 1, 20103: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
c. When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.
d. The threshold for selection as aof the circuit that must comply with the standard will vary
based on the loading duration assumed in the development of the Facility Rating.
i.

If the Facility Rating is based on a loading duration of up to and including four hours,
the circuit must comply with the standard if the loading exceeds 115% of the Facility
Rating.

ii.

iii.

If the Facility Rating is based on a loading duration of greater than eight hours, the
circuit must comply with the standard if the loading exceeds 130% of the Facility
Rating.

e. RadialRadially operated circuits serving only load are excluded.
B5. EachThe circuit thatis selected by the Planning Coordinator may include based on other technical
studies or assessments. , other than those specified in criteria B1 through B4, in consultation with
the Facility owner.
B6. The circuit is mutually agreed upon for inclusion by the Planning Coordinator and the Facility
owner.

Draft 2: November 1, 20103: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability

A. Introduction
1. Title: Transmission Relay Loadability
2. Number:

PRC-023-12

3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with
system operators’ ability to take remedial action to protect system reliability and; be set to
reliably detect all fault conditions and protect the electrical network from these faults.
4. Applicability:
4.1. Functional Entity
4.1.1 Transmission Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to facilitiescircuits defined below: in 4.2.1
(Circuits Subject to Requirements R1 – R5).
4.1.2 Generator Owners with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to
Requirements R1 – R5).
4.1.3 Distribution Providers with load-responsive phase protection systems as described in
PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1(Circuits Subject to
Requirements R1 – R5), provided those circuits have bi-directional flow capabilities.
4.1.4 Planning Coordinators
4.2. Circuits
4.2.1 Circuits Subject to Requirements R1 – R5
4.1.1.14.2.1.1 Transmission lines operated at 200 kV and above.
4.2.1.2 Transmission lines operated at 100 kV to 200 kV as designatedselected by the
Planning Coordinator as.
4.1.1.24.2.1.3 Transmission lines operated below 100 kV that are included on a critical
tofacilities list defined by the reliability ofRegional Entity 1 and selected by the
Bulk Electric System.Planning Coordinator in accordance with R6.
4.1.1.34.2.1.4 Transformers with low voltage terminals connected at 200 kV and above.
4.1.1.44.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV
as designatedselected by the Planning Coordinator as critical to the reliability
of the Bulk Electric System.
4.2.1.6 Generator OwnersTransformers with load-responsive phase low voltage
terminals connected below 100 kV that are included on a critical facilities list
defined by the Regional Entity and selected by the Planning Coordinator in
accordance with R6.
4.2.2 Circuits Subject to Requirement R6
4.2.2.1 Transmission lines operated at 100 kV to 200 kV and transformers with low
voltage terminals connected at 100 kV to 200 kV
1

If the Regional Entity has developed such a list.

Draft 3: January 24, 2011

For the addition to Requirement R1, criterion 10, to set transformer fault
protection systemsrelays and transmission line relays on transmission
lines terminated only with a transformer such that the protection settings
do not expose the transformer to fault level and duration that exceeds its
mechanical withstand capability, the first day of the first calendar quarter
12 months after applicable regulatory approval, or in those jurisdictions
where no regulatory approval is required, the first day of the first
calendar quarter 12 months after Board of Trustees adoption.

4.1.1.4.15.1.1.1.2 For supervisory elements as described in PRC-023-2 Attachment A, applied to facilities defined in 4.Section 1.1 through
4.1.46, the first day of the first calendar quarter 24 months after
applicable regulatory approvals, or in those jurisdictions where
regulatory approval is not required, the first day of the first calendar
quarter 24 months after Board of Trustees adoption.
4.2. Distribution Providers with load-responsive phase protection systemsFor switch-on-to-fault
schemes as described in PRC-023-2 - Attachment A, applied according to facilities defined
in 4.1.1 through 4.1.4., provided that those facilities have bi-directional flow capabilities.
4.3. Planning Coordinators.
5. Effective Dates 2:
5.1. Requirement 1, Requirement 2:
5.1.1 For circuits described in 4.1.1 and 4.Section 1.3 above (except for switch-on-tofault schemes) —, the beginninglater of the first day of the first calendar quarter
followingafter applicable regulatory approvals.
5.1.1.1.15.1.1.1.3 For circuits described in 4.1.approval of PRC-023-2 and 4.1.4
above (including switch-on-to-fault schemes) — at the beginningor the
first day of the first calendar quarter 39 months following applicable
regulatory approvals. approval of PRC-023-1; or in those jurisdictions
where no regulatory approval is required, the later of the first day of the

2 Temporary Exceptions that have already been approved by the NERC Planning Committee via the NERC System
Protection and Control Task Force prior to the approval of this standard shall not result in either findings of noncompliance or sanctions if all of the following apply: (1) the approved requests for Temporary Exceptions include a
mitigation plan (including schedule) to come into full compliance, and (2) the non-conforming relay settings are
mitigated according to the approved mitigation plan.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
first calendar quarter after Board of Trustees adoption of PRC-023-2 or
July 1, 2011.
5.1.2 Each Transmission Owner, Generator Owner, and Distribution Provider shall have 24
months after being notified by its For circuits identified by the Planning Coordinator
pursuant to R3.3 to comply with R1 (including all sub-requirements) for each facility
that is added toRequirement R6
5.1.2.1 The later of the first day of the first calendar quarter 39 months following
notification by the Planning Coordinator’s critical facilities list
determinedCoordinator of a circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B, or the first day of the first
calendar year in which any criterion in Attachment B applies.
5.2. Requirements R2 and R3
5.2.1 For transmission lines operating at 200 kV and above and transformers with low
voltage terminals connected at 200 kV and above.
5.2.1.1 The first day of the first calendar quarter after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day
of the first calendar quarter after Board of Trustees adoption.
5.1.25.2.2 For circuits identified by the Planning Coordinator pursuant to R3.1.Requirement
R6
5.2. Requirement 3: 18 months following applicable regulatory approvals.
5.2.2.1 RequirementsThe later of the first day of the first calendar quarter 39 months
following notification by the Planning Coordinator of a circuit’s inclusion on a
list of circuits subject to PRC-023-2 per application of Attachment B, or the
first day of the first calendar year in which any criterion in Attachment B
applies.
5.3. Requirements R4 and R5
The first day of the first calendar quarter six months after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter six months after Board of Trustees adoption.
5.4. Requirement R6
The first day of the first calendar quarter 18 months after applicable regulatory approval,
or in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter 18 months after Board of Trustees adoption.
B. Requirements
R1.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal
Facility Rating of a circuit, for the available defined loading duration nearest 4 hours
(expressed in amperes).
2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal
15-minute Facility Rating 3 of a circuit (expressed in amperes).
3. Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sending-end and
receiving-end voltages and either reactance or complex impedance) of the circuit
(expressed in amperes) using one of the following to perform the power transfer
calculation:
•

An infinite source (zero source impedance) with a 1.00 per unit bus voltage at each
end of the line.

•

An impedance at each end of the line, which reflects the actual system source
impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate
at or below the maximum power transfer capability of the line, determined as the greater of:
•

115% of the highest emergency rating of the series capacitor.

•

115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with R1.Requirement R1, criterion 3, using the
full line inductive reactance.

5. Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes).
6. Set transmission line relays applied on transmission lines connected to generation stations
remote to load so they do not operate at or below 230% of the aggregated generation
nameplate capability.
7. Set transmission line relays applied at the load center terminal, remote from generation
stations, so they do not operate at or below 115% of the maximum current flow from the
load to the generation source under any system configuration.
8. Set transmission line relays applied on the bulk system-end of transmission lines that serve
load remote to the system so they do not operate at or below 115% of the maximum current
flow from the system to the load under any system configuration.
9. Set transmission line relays applied on the load-end of transmission lines that serve load
remote to the bulk system so they do not operate at or below 115% of the maximum current
flow from the load to the system under any system configuration.
10. Set transformer fault protection relays and transmission line relays on transmission lines
terminated only with a transformer so that theythe relays do not operate at or below the
greater of:
•

150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.

3
When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
•
10.1

115% of the highest operator established emergency transformer rating.
Set load responsive transformer fault protection relays, if used, such that the
protection settings do not expose the transformer to a fault level and duration that
exceeds the transformer’s mechanical withstand capability 4.

11. For transformer overload protection relays that do not comply with R1.the loadability
component of Requirement R1, criterion 10 set the relays according to one of the
following:
•

Set the relays to allow the transformer to be operated at an overload level of at least
150% of the maximum applicable nameplate rating, or 115% of the highest operator
established emergency transformer rating, whichever is greater. The protection must
allow this overload, for at least 15 minutes to allowprovide time for the operator to
take controlled action to relieve the overload.

•

12. When the desired transmission line capability is limited by the requirement to adequately
protect the transmission line, set the transmission line distance relays to a maximum of
125% of the apparent impedance (at the impedance angle of the transmission line) subject
to the following constraints:
a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the
manufacturer.
b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit
voltage and a power factor angle of 30 degrees.
c. Include a relay setting component of 87% of the current calculated in Requirement
R1., criterion 12.2 in the Facility Rating determination for the circuit.
13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.

As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer
Through-Fault-Current Duration, Clause 4.4, Figure 4
5

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
R3.R4.
The Planning Coordinator shall determine which of the facilities
(transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals
connected at 100 kV to 200 kV) in its Planning Coordinator Area are critical to the reliability
of the Bulk Electric System to identify the facilities from 100 kV to 200 kVEach Transmission
Owner, Generator Owner, and Distribution Provider that must meetchooses to use Requirement
1 to prevent potential cascade tripping that may occur when protective relay settings limit
transmission R1 criterion 2 as the basis for verifying transmission line relay loadability shall
provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an
updated list of circuits associated with those transmission line relays at least once each calendar
year, with no more than 15 months between reports. [Violation Risk Factor: MediumLower]
[Time Horizon: Long Term Planning]
R5.

1.2
R6.

This process shall consider input from adjoining Planning Coordinators and
affected Reliability Coordinators.

Thecircuits in its Planning Coordinator shall maintain a current list of facilities
determined according to the process described in R3.1.

Maintain a list of circuits subject to PRC-023-2 per application of Attachment B,
including identification of the first calendar year in which any criterion in Attachment B
applies.

6.36.2
Provide the list of circuits to all Regional Entities, Reliability Coordinators,
Transmission Owners, Generator Owners, and Distribution Providers within 30its
Planning Coordinator area within 30 calendar days of the establishment of the initial list
and within 30 calendar days of any changes to thethat list.
C. Measures
M1. TheEach Transmission Owner, Generator Owner, and Distribution Provider shall each have
evidence such as spreadsheets or summaries of calculations to show that each of its
transmission relays areis set according to one of the criteria in R1.Requirement R1, criterion 1
through R1.13. ( and shall have evidence such as coordination curves or summaries of
calculations that show that relays set per criterion 10 do not expose the transformer to fault
levels and durations beyond those indicated in the standard. (R1)
M1.M2.
Each Transmission Owner, Generator Owner, and Distribution Provider
shall have evidence such as spreadsheets or summaries of calculations to show that each of its
out-of-step blocking elements is set to allow tripping of phase protective relays for faults that

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
occur during the loading conditions used to verify transmission line relay loadability per
Requirement R1. (R2)
M2.M3.
TheEach Transmission Owner, Generator Owner, and Distribution Provider
with transmission relays set according to the criteria in Requirement R1., criterion 6, R1.7,
R1.8, R1.9, R1.12, or R.13 shall have evidence such as Facility Rating spreadsheets or Facility
Rating database to show that it used the calculated circuit capability as the Facility Rating of
the circuit and evidence such as dated correspondence that the resulting Facility Rating was
agreed to by its associated Planning Coordinator, Transmission Operator, and Reliability
Coordinator. (R2R3)
M4. The Each Transmission Owner, Generator Owner, or Distribution Provider that sets
transmission line relays according to Requirement R1, criterion 2 shall have evidence such as
dated correspondence to show that it provided its Planning Coordinator shall have,
Transmission Operator, and Reliability Coordinator with an updated list of circuits associated
with those transmission line relays within the required timeframe. The updated list may either
be a documented process for the determination of facilities as described in R3full list or a list
of incremental changes to the previous list. (R4)
M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission
line relays according to Requirement R1, criterion 12 shall have evidence such as dated
correspondence that it provided an updated list of the circuits associated with those relays to its
Regional Entity within the required timeframe. The updated list may either be a full list or a
list of incremental changes to the previous list. (R5)
M3.M6.
Each Planning Coordinator shall have evidence such as power flow results,
calculation summaries, or study reports that it used the criteria established within Attachment B
to determine the circuits in its Planning Coordinator area for which applicable entities must
comply with the standard as described in Requirement R6. The Planning Coordinator shall
have a currentdated list of such facilitiescircuits and shall have evidence such as dated
correspondence that it provided the list to the approriateRegional Entities, Reliability
Coordinators, Transmission OperatorsOwners, Generator OperatorsOwners, and Distribution
Providers. (R3 within its Planning Coordinator area within the required timeframe. (R6)

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
•

For entities that do not work for the Regional Entity, the Regional Entity shall serve as
the Compliance Enforcement Authority.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
•

For functional entities that work for their Regional Entity, the ERO shall serve as the
Compliance Enforcement Authority.

1.3.1.2.

Data Retention

Compliance Audit

•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability
None.

Draft 3: January 24, 2011

Standard PRC-023-2 — Transmission Relay Loadability

Violation Severity Levels:

R#Requirement
R1

Lower
N/A

Moderate
Evidence that relay settings
comply with criteria in R1.1
though 1.13 exists, but
evidence is incomplete or
incorrect for one or more of the
subrequirements. N/A

High
N/A

Formatted Table

Severe
Relay settings do not comply
with any of the sub
requirements R1.1 through
R1.13
OR
Evidence does not exist to
support that relay settings
comply with one of the criteria
in subrequirements R1.1
through R1.13.The responsible
entity did not use any one of the
following criteria (Requirement
R1 criterion 1 through 13) for any
specific circuit terminal to prevent
its phase protective relay settings
from limiting transmission system
loadability while maintaining
reliable protection of the Bulk
Electric System for all fault
conditions.
OR
The responsible entity did not
evaluate relay loadability at 0.85
per unit voltage and a power
factor angle of 30 degrees.

N/A

Draft 3: January 21, 2011

N/A

The responsible entity failed to
ensure that its out-of-step
blocking elements allowed
tripping of phase protective relays
for faults that occur during the
loading conditions used to verify
transmission line relay loadability

Standard PRC-023-2 — Transmission Relay Loadability
R#Requirement

Lower

Moderate

High

Formatted Table

Severe
per Requirement R1.

R2R3

Criteria described in R1.6,
R1.7. R1.8. R1.9, R1.12, or
R.13 was used but evidence
does not exist that agreement
was obtained in accordance
with R2.N/A

N/A

The responsible entity that uses a
circuit capability with the
practical limitations described in
Requirement R1 criterion 6, 7, 8,
9, 12, or 13 did not use the
calculated circuit capability as the
Facility Rating of the circuit.
OR
The responsible entity did not
obtain the agreement of the
Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.

N/A

The responsible entity did not
provide its Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with an
updated list of circuits that have
transmission line relays set
according to the criteria
established in Requirement R1
criterion 2 at least once each
calendar year, with no more than
15 months between reports.

N/A

The responsible entity did not
provide its Regional Entity, with
an updated list of circuits that
have transmission line relays set
according to the criteria
established in Requirement R1
criterion 12 at least once each
calendar year, with no more than
15 months between reports.

Draft 3: January 21, 2011

Formatted Table

Standard PRC-023-2 — Transmission Relay Loadability
R#Requirement
R3R6

Moderate

High

Severe

Formatted Table

Provided the list of facilities
criticalThe Planning Coordinator
used the criteria established within
Attachment B to determine the
reliability ofcircuits in its
Planning Coordinator area for
which applicable entities must
comply with the Bulk Electric
Systemstandard and met parts 6.1
and 6.2, but more than 15 months
and less than 24 months lapsed
between assessments.

Provided the list of facilities
criticalThe Planning Coordinator
used the criteria established
within Attachment B to determine
the reliability ofcircuits in its
Planning Coordinator area for
which applicable entities must
comply with the Bulk Electric
Systemstandard and met parts 6.1
and 6.2, but 24 months or more
lapsed between assessments.

Does not have a process in
place to determine facilities
that are critical to the reliability
of the Bulk Electric System.
The Planning Coordinator failed
to use the criteria established
within Attachment B to determine
the circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard.

Formatted Table

Lower
N/A

OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to the appropriatedetermine the
circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.1 and
6.2 but failed to include the
calendar year in which any
criterion in Attachment B first
applies.
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine the circuits in its
Planning Coordinator area for
which applicable entities must

Draft 3: January 21, 2011

OR
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to the appropriatedetermine the
circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard and met 6.1 and
6.2 but provided the list of circuits
to the Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution
Providers within its Planning
Coordinator area between 46 days
and 60 days after list was
established or updated. (part 6.2)

Does not maintain a current list
of facilities critical to the
reliability of the Bulk Electric
System,
OR
Did notThe Planning Coordinator
used the criteria established
within Attachment B, at least once
each calendar year, with no more
than 15 months between
assessments to determine the
circuits in its Planning
Coordinator area for which
applicable entities must comply
with the standard but failed to
meet parts 6.1 and 6.2.
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine the circuits in its

Standard PRC-023-2 — Transmission Relay Loadability
R#Requirement

Lower

Draft 3: January 21, 2011

High

Formatted Table

Severe
Planning Coordinator area for
which applicable entities must
comply with the standard but
failed to maintain the list of
circuits determined according to
the process described in
Requirement R6. (part 6.1)
OR
The Planning Coordinator used
the criteria established within
Attachment B at least once each
calendar year, with no more than
15 months between assessments
to determine the circuits in its
Planning Coordinator area for
which applicable entities must
comply with the standard and met
6.1 but failed to provide the list of
facilities critical to the reliability
of the Bulk Electric System to
the appropriatecircuits to the
Reliability Coordinators,
Transmission Owners, Generator
Owners, and Distribution
Providers, within its Planning
Coordinator area or provided the
list more than 60 days after the
list was established or updated.
(part 6.2)

Standard PRC-023-2 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.
Version History
Version

Date

Action

Change Tracking

February 12, 2008

Approved by Board of Trustees

New

March 19, 2008

Corrected typo in last sentence of Severe VSL Errata
for Requirement 3 — “then” should be “than.”

March 18, 2010

Approved by FERC

November 1, 2010

Revised to address directives from Order 733

Draft 3: January 21, 2011

1.5.1

Permissive overreach transfer trip (POTT).

1.5.2

Permissive under-reach transfer trip (PUTT).

1.5.3

Directional comparison blocking (DCB).

1.5.4

Directional comparison unblocking (DCUB).

This standard includes out-of-step blocking schemes which shall be evaluated to ensure that they
do not block trip for faults during the loading conditions defined within the requirements.
1.6. Supervisory elements associated with current-based, communication-assisted schemes where
the scheme is capable of tripping for loss of communications.

3.2. The following protection systems are excluded from requirements of this standard:
3.1.2.1.
Relay elements that are only enabled when other relays or associated systems fail. For
example:
•

Overcurrent elements that are only enabled during loss of potential conditions.

•

Elements that are only enabled during a loss of communications. except as noted in
section 1.6

3.2.2.2.

Protection systems intended for the detection of ground fault conditions.

3.3.2.3.

Protection systems intended for protection during stable power swings.

3.4.2.4.

Generator protection relays that are susceptible to load.

Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.

3.8.2.8.

Relay elements associated with DCdc lines.

3.9.2.9.

Relay elements associated with DCdc converter transformers.

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
PRC-023 — Attachment B
Circuits to Evaluate

•
•

Criteria
If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for
that circuit.
B1. The circuit is a monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Québec Interconnection, that has been included to address
reliability concerns for loading of that circuit, as confirmed by the applicable Planning
Coordinator.
B2. The circuit is a monitored Facility of an IROL, where the IROL was determined in the planning
horizon pursuant to FAC-010.
B3. The circuit forms a path (as agreed to by the plant owner and the transmission entity) to supply
off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements
(NPIRs) pursuant to NUC-001.
B4. The circuit is identified through the following sequence of power flow analyses 6 performed by the
Planning Coordinator for the one-to-five-year planning horizon:
a. Simulate double contingency combinations selected by engineering judgment, without
manual system adjustments in between the two contingencies (reflects a situation where a
System Operator may not have time between the two contingencies to make appropriate
system adjustments).
b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in
consultation with the Facility owner, against a threshold based on the Facility Rating assigned
for that circuit and used in the power flow case by the Planning Coordinator.
c. When more than one Facility Rating for that circuit is available in the power flow case, the
threshold for selection will be based on the Facility Rating for the loading duration nearest
four hours.
d. The threshold for selection of the circuit will vary based on the loading duration assumed in
the development of the Facility Rating.

Past analyses may be used to support the assessment if no material changes to the system have occurred since the
last assessment

Draft 3: January 21, 2011

Standard PRC-023-2 — Transmission Relay Loadability
i.

If the Facility Rating is based on a loading duration of up to and including four hours,
the circuit must comply with the standard if the loading exceeds 115% of the Facility
Rating.

ii.

iii.

If the Facility Rating is based on a loading duration of greater than eight hours, the
circuit must comply with the standard if the loading exceeds 130% of the Facility
Rating.

Draft 3: January 21, 2011

Standards Announcement
Successive Ballot and Non-binding Poll Open
Project 2010-13 – Relay Loadability Order 733 Modifications
January 24-February 13, 2011
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2010-13: Revisions to Relay Loadability for Order 733
PRC-023-2 — Transmission Relay Loadability has been posted for a 20-day successive ballot of the proposed
standard and its associated implementation plan through 8 p.m. on February 13, 2011. A non-binding poll of
the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) will be conducted during
the same time.
Registered Ballot Body members who joined the ballot pool to vote on the standard have already been
automatically entered in a separate pool to participate in the non-binding poll for the VRFs and VSLs. For
ballot pool members, the non-binding poll appears in the list of current ballots, and is labeled accordingly.
Instructions
Members of the ballot pools associated with this project may log in and submit their votes from the following
page: https://standards.nerc.net/CurrentBallots.aspx
Background
This standard was revised to address a set of directives in Order 733 and must be submitted to FERC by March
18, 2011. To meet this delivery date, the Standards Committee authorized use of the expedited standard
development process. Under the expedited standard development process, the Standards Committee may alter
certain steps in the standard development process to meet a regulatory deadline. In this case, the Standards
Committee authorized the drafting team to conduct successive ballots without parallel comment periods. To
allow stakeholders time to review the changes made between ballots, the Standards Committee authorized an
extended ballot window of 20 calendar days, rather than 10 calendar days.
Next Steps
Voting results will be posted and announced after the ballot windows close.
Project Background
When FERC issued Order 733, approving PRC-023-1 —Transmission Relay Loadability, it directed several
changes to that standard and also directed development of one or more new standards within specified time
periods. NERC filed for clarification and rehearing, asking for clarity and an extension of time to address the
directives; however, without a response to the requests for clarification and rehearing, NERC must proceed as
though these requests will be denied.
The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases. Phase I

addresses the specific directives from Order 733 that identified required modifications to various elements
within PRC-023-1. Phase II addresses directives associated with development of a new standard to address
generator relay loadability. Phase III addresses directives associated with writing requirements to address
protective relay operations due to power swings.
More information on this project may be found on the project page:
http://www.nerc.com/filez/standards/SAR_Project%202010-13_Order%20733%20Relay%20Modifiations.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Ballot Name: 2010-13 Relay Loadability Order Non-Binding Poll
Ballot Period: 1/24/2011 - 2/14/2011
Total # Opinions: 173
Total Ballot Pool: 324
80% of those who registered to participate provided an opinion; 65% of

Summary Results: those who provided an opinion indicated support for the VRFs and VSLs that
were proposed.

Individual Ballot Pool Results

Segment

Organization

Member

Opinion

Allegheny Power

Rodney Phillips

Affirmative

Ameren Services

Kirit S. Shah

Affirmative

American Electric Power

Paul B. Johnson

American Transmission Company,
Andrew Z Pusztai
LLC

APS

Barbara McMinn

Arizona Public Service Co.

Robert D Smith

Abstain

Associated Electric Cooperative,
Inc.

John Bussman

Affirmative

Avista Corp.

Scott Kinney

Affirmative

BC Transmission Corporation

Gordon Rawlings

Affirmative

Beaches Energy Services

Joseph S.
Stonecipher

Black Hills Corp

Eric Egge

Bonneville Power Administration

Donald S. Watkins

CenterPoint Energy

Paul Rocha

Central Maine Power Company

Kevin L Howes

City of Tacoma, Department of
Public Utilities, Light Division, dba Chang G Choi
Tacoma Power

Negative

Comments

View

Negative

Abstain
Negative
Abstain

Affirmative

City of Vero Beach

Randall McCamish

City Utilities of Springfield,
Missouri

Jeff Knottek

Affirmative

Clark Public Utilities

Jack Stamper

Affirmative

Cleco Power LLC

Danny McDaniel

Colorado Springs Utilities

Paul Morland

Commonwealth Edison Co.

Gregory Campbell

Consolidated Edison Co. of New
York

Christopher L de
Graffenried

Abstain

Dairyland Power Coop.

Robert W. Roddy

Affirmative

Dayton Power & Light Co.

Hertzel Shamash

Affirmative

Dominion Virginia Power

Michael S Crowley

Abstain

Duke Energy Carolina

Douglas E. Hils

Affirmative

East Kentucky Power Coop.

George S. Carruba

Affirmative

Empire District Electric Co.

Ralph Frederick
Meyer

Affirmative

Entergy Corporation

George R. Bartlett

FirstEnergy Energy Delivery

Robert Martinko

Florida Keys Electric Cooperative
Assoc.

Dennis Minton

Negative

Gainesville Regional Utilities

Luther E. Fair

Negative

View

Georgia Transmission Corporation Harold Taylor, II

Negative

View

Great River Energy

Gordon Pietsch

Negative

View

Hoosier Energy Rural Electric
Cooperative, Inc.

Robert Solomon

Affirmative

Hydro One Networks, Inc.

Ajay Garg

Idaho Power Company

Ronald D. Schellberg

International Transmission

Michael Moltane

Negative

View

Negative
Affirmative

Abstain
Affirmative

Abstain

Affirmative

Company Holdings Corp
1

Kansas City Power & Light Co.

Michael Gammon

Abstain

Keys Energy Services

Stan T. Rzad

Negative

Lake Worth Utilities

Walt Gill

Negative

Lakeland Electric

Larry E Watt

Lee County Electric Cooperative

John W Delucca

Lincoln Electric System

Doug Bantam

Long Island Power Authority

Robert Ganley

Affirmative

Lower Colorado River Authority

Martyn Turner

Affirmative

Manitoba Hydro

Joe D Petaski

Negative

View

MidAmerican Energy Co.

Terry Harbour

Negative

View

Minnkota Power Coop. Inc.

Richard Burt

Negative

View

National Grid

Saurabh Saksena

Affirmative

View

Nebraska Public Power District

Richard L. Koch

New Brunswick Power
Transmission Corporation

Randy MacDonald

Affirmative

New York Power Authority

Arnold J. Schuff

Affirmative

Northeast Utilities

David H. Boguslawski

Affirmative

Northern Indiana Public Service
Co.

Kevin M Largura

NorthWestern Energy

John Canavan

Abstain

Ohio Valley Electric Corp.

Robert Mattey

Affirmative

Omaha Public Power District

Douglas G
Peterchuck

Affirmative

Oncor Electric Delivery

Michael T. Quinn

Otter Tail Power Company

Daryl Hanson

Pacific Gas and Electric Company

Chifong L. Thomas

View

Affirmative
Abstain

Abstain

Negative
Affirmative

PacifiCorp

Colt Norrish

Affirmative

PECO Energy

Ronald Schloendorn

Affirmative

Platte River Power Authority

John C. Collins

Affirmative

Portland General Electric Co.

Frank F. Afranji

Affirmative

Potomac Electric Power Co.

David Thorne

Affirmative

PowerSouth Energy Cooperative

Larry D. Avery

Affirmative

PPL Electric Utilities Corp.

Brenda L Truhe

Abstain

Public Service Company of New
Mexico

Laurie Williams

Abstain

Public Service Electric and Gas Co. Kenneth D. Brown

Puget Sound Energy, Inc.

Catherine Koch

Rochester Gas and Electric Corp.

John C. Allen

Sacramento Municipal Utility
District

Tim Kelley

Salt River Project

Robert Kondziolka

Abstain

Santee Cooper

Terry L. Blackwell

Negative

SCE&G

Henry Delk, Jr.

Abstain

Seattle City Light

Pawel Krupa

Abstain

Sierra Pacific Power Co.

Rich Salgo

Abstain

Snohomish County PUD No. 1

Long T Duong

South Texas Electric Cooperative

Richard McLeon

Southern California Edison Co.

Dana Cabbell

Southern Company Services, Inc.

Horace Stephen
Williamson

Southern Illinois Power Coop.

William G. Hutchison

Southwest Transmission
Cooperative, Inc.

James L. Jones

Abstain

Abstain
Affirmative

Affirmative
Abstain
Negative

Negative
Affirmative

Southwestern Power
Administration

Gary W Cox

Affirmative

Sunflower Electric Power
Corporation

Noman Lee Williams

Affirmative

Tampa Electric Co.

Beth Young

Tennessee Valley Authority

Larry Akens

Abstain

Texas Municipal Power Agency

Frank J. Owens

Abstain

Transmission Agency of Northern
California

James W. Beck

Abstain

Tri-State G & T Association, Inc.

Keith V Carman

Negative

Tucson Electric Power Co.

John Tolo

United Illuminating Co.

Jonathan Appelbaum

Westar Energy

Allen Klassen

Western Area Power
Administration

Brandy A Dunn

Western Farmers Electric Coop.

Forrest Brock

Xcel Energy, Inc.

Gregory L Pieper

Alberta Electric System Operator

Mark B Thompson

BC Hydro

Venkataramakrishnan
Vinnakota

California ISO

Gregory Van Pelt

Electric Reliability Council of Texas,
Chuck B Manning
Inc.

Independent Electricity System
Operator

Kim Warren

ISO New England, Inc.

Kathleen Goodman

Midwest ISO, Inc.

Jason L Marshall

New Brunswick System Operator

Alden Briggs

New York Independent System

Affirmative
Abstain
Negative
Affirmative

Abstain
Affirmative

Negative

Affirmative

Negative

View

Affirmative

Gregory Campoli

Operator
2

PJM Interconnection, L.L.C.

Tom Bowe

Affirmative

Southwest Power Pool

Charles H Yeung

Alabama Power Company

Richard J. Mandes

Affirmative

Allegheny Power

Bob Reeping

Affirmative

Ameren Services

Mark Peters

American Electric Power

Raj Rana

Anaheim Public Utilities Dept.

Kelly Nguyen

Abstain

APS

Steven Norris

Abstain

Arkansas Electric Cooperative
Corporation

Philip Huff

Abstain

Atlantic City Electric Company

James V. Petrella

Affirmative

Avista Corp.

Robert Lafferty

Affirmative

BC Hydro and Power Authority

Pat G. Harrington

Blue Ridge Power Agency

Duane S Dahlquist

Bonneville Power Administration

Rebecca Berdahl

Central Lincoln PUD

Steve Alexanderson

City of Farmington

Linda R. Jacobson

City of Green Cove Springs

Gregg R Griffin

Negative

City of Leesburg

Phil Janik

Negative

Cleco Corporation

Michelle A Corley

Negative

ComEd

Bruce Krawczyk

Consolidated Edison Co. of New
York

Peter T Yost

Cowlitz County PUD

Russell A Noble

Affirmative

Delmarva Power & Light Co.

Michael R. Mayer

Affirmative

Abstain

Negative
Affirmative

View

Affirmative
Abstain

Detroit Edison Company

Kent Kujala

Affirmative

Dominion Resources Services

Michael F Gildea

Duke Energy Carolina

Henry Ernst-Jr

Affirmative

East Kentucky Power Coop.

Sally Witt

Affirmative

Entergy

Joel T Plessinger

FirstEnergy Solutions

Kevin Querry

Florida Municipal Power Agency

Joe McKinney

Florida Power Corporation

Lee Schuster

Georgia Power Company

Anthony L Wilson

Georgia System Operations
Corporation

R Scott S. BarfieldMcGinnis

Negative

Great River Energy

Sam Kokkinen

Negative

Hydro One Networks, Inc.

David L Kiguel

Abstain

JEA

Garry Baker

Abstain

Kansas City Power & Light Co.

Charles Locke

Abstain

Kissimmee Utility Authority

Gregory David
Woessner

Abstain

Lakeland Electric

Mace Hunter

Lincoln Electric System

Bruce Merrill

Louisville Gas and Electric Co.

Charles A. Freibert

Manitoba Hydro

Greg C. Parent

Negative

MidAmerican Energy Co.

Thomas C. Mielnik

Negative

Mississippi Power

Don Horsley

Muscatine Power & Water

John S Bos

Abstain

Nebraska Public Power District

Tony Eddleman

Abstain

New York Power Authority

Marilyn Brown

Abstain

Affirmative

Negative
Affirmative
View

Affirmative

View

Affirmative

Niagara Mohawk (National Grid
Company)

Michael Schiavone

Affirmative

Northern Indiana Public Service
Co.

William SeDoris

Affirmative

Orange and Rockland Utilities, Inc. David Burke

Orlando Utilities Commission

Ballard Keith Mutters

Abstain

PacifiCorp

John Apperson

Abstain

PECO Energy an Exelon Co.

Vincent J. Catania

Platte River Power Authority

Terry L Baker

PNM Resources

Michael Mertz

Potomac Electric Power Co.

Robert Reuter

Progress Energy Carolinas

Sam Waters

Public Service Electric and Gas Co. Jeffrey Mueller

Abstain

Public Utility District No. 1 of
Chelan County

Abstain

Public Utility District No. 2 of Grant
Greg Lange
County

Sacramento Municipal Utility
District

James Leigh-Kendall

Salt River Project

John T. Underhill

San Diego Gas & Electric

Scott Peterson

Santee Cooper

Zack Dusenbury

Negative

Seattle City Light

Dana Wheelock

Abstain

Seminole Electric Cooperative, Inc. James R Frauen

South Carolina Electric & Gas Co.

Hubert C. Young

Southern California Edison Co.

David Schiada

Negative

Tacoma Public Utilities

Travis Metcalfe

Affirmative

Tampa Electric Co.

Ronald L Donahey

Kenneth R. Johnson

Negative

Affirmative

Negative

Affirmative
Abstain

Affirmative

View

Tennessee Valley Authority

Ian S Grant

Negative

Tri-State G & T Association, Inc.

Janelle Marriott

Wisconsin Electric Power Marketing James R. Keller

Xcel Energy, Inc.

Alliant Energy Corp. Services, Inc. Kenneth Goldsmith

Abstain

American Public Power Association Allen Mosher

Abstain

Arkansas Electric Cooperative
Corporation

Ronnie Frizzell

Abstain

Central Lincoln PUD

Shamus J Gamache

City of New Smyrna Beach Utilities
Timothy Beyrle
Commission

Consumers Energy

David Frank Ronk

Cowlitz County PUD

Rick Syring

Affirmative

Detroit Edison Company

Daniel Herring

Affirmative

Florida Municipal Power Agency

Frank Gaffney

Fort Pierce Utilities Authority

Thomas W. Richards

Negative

Georgia System Operations
Corporation

Guy Andrews

Negative

Illinois Municipal Electric Agency

Bob C. Thomas

Ohio Edison Company

Douglas Hohlbaugh

Public Utility District No. 1 of
Douglas County

Henry E. LuBean

Public Utility District No. 1 of
Snohomish County

John D. Martinsen

Sacramento Municipal Utility
District

Mike Ramirez

Seattle City Light

Hao Li

Seminole Electric Cooperative, Inc. Steven R Wallace

View

Abstain

Michael Ibold

Affirmative
Negative
Abstain

View

Abstain
Affirmative

Abstain

Affirmative
Abstain

Tacoma Public Utilities

Keith Morisette

Affirmative

Tallahassee Electric

Allan Morales

Affirmative

Wisconsin Energy Corp.

Anthony Jankowski

Abstain

Edwin B Cano

AEP Service Corp.

Brock Ondayko

Amerenue

Sam Dwyer

Arizona Public Service Co.

Edward Cambridge

Avista Corp.

Edward F. Groce

Affirmative

Bonneville Power Administration

Francis J. Halpin

Negative

City and County of San Francisco

Daniel Mason

City of Tacoma, Department of
Public Utilities, Light Division, dba Max Emrick
Tacoma Power

City of Tallahassee

Alan Gale

Cleco Power

Stephanie Huffman

Consolidated Edison Co. of New
York

Wilket (Jack) Ng

Consumers Energy

James B Lewis

Covanta Energy

Samuel Cabassa

Cowlitz County PUD

Bob Essex

Affirmative

Detroit Edison Company

Christy Wicke

Affirmative

Dominion Resources, Inc.

Mike Garton

Affirmative

Duke Energy

Dale Q Goodwine

Affirmative

East Kentucky Power Coop.

Stephen Ricker

Affirmative

El Paso Electric Company

Alfred W Morgan

Electric Power Supply Association

Jack Cashin

View

Energy Northwest - Columbia

Negative

View

Affirmative
Abstain

Affirmative

Abstain

Abstain
Affirmative
Abstain

Doug Ramey

Generating Station
5

Entergy Corporation

Stanley M Jaskot

Exelon Nuclear

Michael Korchynsky

Florida Municipal Power Agency

David Schumann

Great River Energy

Cynthia E Sulzer

Green Country Energy

Greg Froehling

Indeck Energy Services, Inc.

Rex A Roehl

Kansas City Power & Light Co.

Scott Heidtbrink

Kissimmee Utility Authority

Mike Blough

Lakeland Electric

Thomas J Trickey

Lincoln Electric System

Dennis Florom

Louisville Gas and Electric Co.

Charlie Martin

Luminant Generation Company LLC Mike Laney

Manitoba Hydro

Massachusetts Municipal Wholesale
David Gordon
Electric Company

MidAmerican Energy Co.

Christopher
Schneider

Negative

Nebraska Public Power District

Don Schmit

Abstain

New Harquahala Generating Co.
LLC

Nicholas Q Hayes

New York Power Authority

Gerald Mannarino

Northern California Power Agency

Tracy R Bibb

Northern Indiana Public Service
Co.

Michael K Wilkerson

Occidental Chemical

Michelle DAntuono

Omaha Public Power District

Mahmood Z. Safi

S N Fernando

Abstain
Affirmative

Affirmative
Negative

View

Abstain
Affirmative

Affirmative

Affirmative
Negative

View

Abstain

View

Affirmative

Negative

View

Abstain

Orlando Utilities Commission

Richard Kinas

Pacific Gas and Electric Company

Richard J. Padilla

PacifiCorp

Sandra L. Shaffer

Platte River Power Authority

Pete Ungerman

PPL Generation LLC

Annette M Bannon

Progress Energy Carolinas

Wayne Lewis

Public Service Enterprise Group
Incorporated

Dominick Grasso

Public Utility District No. 1 of Lewis
Steven Grega
County

Sacramento Municipal Utility
District

Bethany Hunter

Salt River Project

Glen Reeves

Santee Cooper

Lewis P Pierce

Seattle City Light

Michael J. Haynes

Seminole Electric Cooperative, Inc. Brenda K. Atkins

Snohomish County PUD No. 1

Sam Nietfeld

South Carolina Electric & Gas Co.

Richard Jones

Southern Company Generation

William D Shultz

Tampa Electric Co.

RJames Rocha

Tenaska, Inc.

Scott M. Helyer

Tennessee Valley Authority

David Thompson

U.S. Army Corps of Engineers

Melissa Kurtz

U.S. Bureau of Reclamation

Martin Bauer P.E.

Wisconsin Electric Power Co.

Linda Horn

Abstain

Wisconsin Public Service Corp.

Leonard Rentmeester

Abstain

Xcel Energy, Inc.

Liam Noailles

Abstain
Affirmative
Abstain
Negative
Abstain

Negative

Affirmative
Abstain
Negative
Abstain
Affirmative
Abstain

Affirmative

Abstain
Negative

View

Affirmative

AEP Marketing

Edward P. Cox

Negative

Ameren Energy Marketing Co.

Jennifer Richardson

Affirmative

Arizona Public Service Co.

Justin Thompson

Affirmative

Bonneville Power Administration

Brenda S. Anderson

Negative

Cleco Power LLC

Robert Hirchak

Negative

Consolidated Edison Co. of New
York

Nickesha P Carrol

Constellation Energy Commodities
Brenda Powell
Group

Abstain

Dominion Resources, Inc.

Louis S. Slade

Abstain

Duke Energy Carolina

Walter Yeager

Affirmative

Entergy Services, Inc.

Terri F Benoit

Abstain

Exelon Power Team

Pulin Shah

Affirmative

FirstEnergy Solutions

Mark S Travaglianti

Affirmative

Florida Municipal Power Agency

Richard L.
Montgomery

Florida Municipal Power Pool

Thomas E Washburn

Florida Power & Light Co.

Silvia P. Mitchell

Abstain

Kansas City Power & Light Co.

Jessica L Klinghoffer

Abstain

Lakeland Electric

Paul Shipps

Affirmative

Lincoln Electric System

Eric Ruskamp

Affirmative

Manitoba Hydro

Daniel Prowse

Negative

New York Power Authority

William Palazzo

Affirmative

Northern Indiana Public Service
Co.

Joseph O'Brien

Affirmative

Omaha Public Power District

David Ried

PacifiCorp

Scott L Smith

View

Abstain

Negative

View

Abstain
Negative

Platte River Power Authority

Carol Ballantine

Affirmative

PPL EnergyPlus LLC

Mark A Heimbach

Abstain

Progress Energy

John T Sturgeon

Negative

PSEG Energy Resources & Trade
LLC

Peter Dolan

Public Utility District No. 1 of
Chelan County

Hugh A. Owen

RRI Energy

Trent Carlson

Sacramento Municipal Utility
District

Claire Warshaw

Salt River Project

Mike Hummel

Santee Cooper

Suzanne Ritter

Negative

Seattle City Light

Dennis Sismaet

Abstain

Seminole Electric Cooperative, Inc. Trudy S. Novak

Affirmative

Tacoma Public Utilities

Michael C Hill

Affirmative

Tennessee Valley Authority

Marjorie S. Parsons

Western Area Power
Administration - UGP Marketing

John Stonebarger

Xcel Energy, Inc.

David F. Lemmons

Abstain

Affirmative

Negative

James A Maenner

Roger C Zaklukiewicz

Affirmative

Edward C Stein

Affirmative

INTELLIBIND

Kevin Conway

JDRJC Associates

Jim D. Cyrulewski

Utility Services, Inc.

Brian Evans-Mongeon

Volkmann Consulting, Inc.

Terry Volkmann

California Energy Commission

William Mitchell
Chamberlain

View

Abstain

Affirmative
Abstain
Negative

Commonwealth of Massachusetts
Department of Public Utilities

Donald E. Nelson

Oregon Public Utility Commission

Jerome Murray

Abstain

Snohomish County PUD No. 1

William Moojen

Abstain

Utah Public Service Commission

Ric Campbell

Affirmative

New York State Reliability Council

Alan Adamson

Affirmative

Northeast Power Coordinating
Council, Inc.

Guy V. Zito

Affirmative

ReliabilityFirst Corporation

Anthony E Jablonski

Affirmative

SERC Reliability Corporation

Carter B Edge

Southwest Power Pool Regional
Entity

Stacy Dochoda

Texas Reliability Entity

Larry D Grimm

Negative

Abstain

Consideration of Comments on Non-binding Poll — Relay Loadability Order 733 (Project 2010-13)
Date of Non-binding Poll: January 24 – February 14, 2011
Summary Consideration: A 20-day non-binding poll was conducted for the Transmission Relay Loadability Version 2 VRF/VSLs from January
24, 2011 to February 14, 2011. The non-binding poll on the VRF/VSLs, 80.0% of those registered provided an opinion, and 65% of those who
provided an opinion indicated support for the VRFs and VSLs that were proposed.
Commenters offered their opinions in a variety of areas that can be summarized as follows:
1. Preference for additional gradations in the proposed VRF/VSLs
2. Some of the proposed VRFs and VSLs are too severe
3. Consideration of the proper Functional Entity to decide on the circuits and equipment that operate at less than or equal to 100 kV that are
subject to this standard
4. Criteria for determination of the ‘critical facilities’ eliminates the facility’s owner ability to establish criticality of its owned equipment
Approximately 50% of the commenters expressed concern about the lack of gradients in the definition of the VSLs. Many thought that having only
one level (Severe) was too extreme, and many requested that multiple severity levels be defined. The drafting team explained that if a VSL is
binary in nature (either the requirement is met or it isn’t), FERC has directed in Order 733 that binary VSLs be treated as Severe. The drafting
team stated that it believes the binary VSLs for Requirements R1 through R5 in PRC-023-2 are consistent with Order 733. Requirement R6 does
have VSLs defined with gradations that are appropriate for the nature of that requirement.
Commenters expressed concern that the VSLs were too severe for the associated impact to reliability. The drafting team noted that the impact to
reliability is not relevant to assigning VSLs. The drafting team clarified that Violation Risk Factors (VRFs) identify the potential reliability
significance of noncompliance with each requirement while Violation Severity Levels (VSLs) define the degree to which compliance with a
requirement was not achieved.
Commenters expressed concern about which of the Functional Entities is best suited to identify which circuits and equipment should be identified
as critical to the reliable operation of the grid. Many thought the standard was providing the Regional Entities with unilateral authority, but the
drafting team noted that PRC-023 does not grant the Regional Entity any authority, but rather reflects language already contained in the NERC
Statement of Compliance Registry Criteria that provides for excluding from the registration list entities that do not own or operate “a transmission
element below 100 kV associated with a facility that is included on a critical facilities list that is defined by the Regional Entity.” However, to
provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under development, the drafting team has
modified this reference in the standard to refer to transmission lines operated below 100 kV and transformers with low voltage terminals connected
below 100 kV that are part of the BES.
The drafting team also indicated that screening of the critical facilities list will be performed by the Planning Coordinator who is required to apply
the criteria in Attachment B to these facilities to identify which circuits on the list are relevant to the reliability objective of PRC-023-2. The
Planning Coordinator must apply the criteria in Attachment B to all facilities operated below 100 kV that are on a critical facilities list. However, the
Facility owners are required to comply with PRC-023-2 only for those circuits selected by the Planning Coordinator in accordance with
Requirement R6.
The drafting team indicated that the process for determining which facilities are critical to the reliable operation of the BES is well contained
because it requires that the determination must (i) be based on technical studies or assessments and (ii) must be made in consultation with the

Facility owner. While the drafting team understands the need for Facility owner input, it also believes it is inappropriate to give the Facility owner
de facto veto power by using the phrase “upon mutual agreement with.” The Planning Coordinator will give due consideration to the Facility
owner’s input, and in cases where the Facility owner disagrees with the determination of the Planning Coordinator, the Facility owner is free to use
the appeals process in Section 1700 of the NERC Rules of Procedure, which was developed to address this concern.
A few commenters provided more technical comments regarding the requirements of the PRC-023-2 standard, and these responses are provided
in coordination with the Consideration of Comments responses with respect to the successive ballot comments.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
1
Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.

Voter

Entity

Edward P.
Cox

AEP
Marketing

Brock
Ondayko

AEP Service
Corp.

Paul B.
Johnson

American
Electric Power

Segment
6

Vote
Negative

Comment
It is unclear why there is an absence of gradients in the VSL for many of the
requirements. For example, there are many similar requirements in other standards
that have VSL thresholds based on a percentage of equipment not meeting the
element(s) of the requirement.

Response: Thank you for your comment.
Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733 and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are consistent
with that Order.

Randall
McCamish

City of Vero
Beach

Thomas E
Washburn

Florida
Municipal
Power Pool

Stan T.
Rzad

Keys Energy
Services

Negative

The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.

February 24, 2011

Voter

Entity

Segment

Vote

Comment
self-regulating, e.g., the Planning Coordinator is separate from the asset owners.
Most of the Planning Coordinators are stakeholder organization whose "Planning
Committees" would make the determination. For entities that do self-regulate, e.g.,
they are both the asset owner and Planning Coordinator, presumably the Regional
Entity could form a stakeholder process with a Planning Committee whose members
include appropriate and balanced representation from the stakeholders. These
"Planning Committees" could be an alternative source for a stakeholder process to
determine criteria for < 100 kV Applicability and apply that criteria while a
continent-wide effort is underway to determine that criteria. These "Planning
Committees" could remain in place to apply the continent-wide criteria to the
regional system.

Response: Thank you for your comment.

The drafting team notes that PRC-023 does not grant the Regional Entity any authority, rather it reflects language already contained in the
NERC Statement of Compliance Registry Criteria that provides for excluding from the registration list entities that do not own or operate “a
transmission element below 100 kV associated with a facility that is included on a critical facilities list that is defined by the Regional Entity
(emphasis added).” However, to provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under
development, the drafting team has modified this reference in the standard to refer to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are part of the BES.
Luther E.
Fair

Gainesville
Regional
Utilities

Negative

Response: Thank you for your comment.

The Regional Entity is not the correct entity to make decisions concerning what <
100 kV equipment is critical or not. It also is not in alignment with the regulatory
construct of a stakeholder process described in Section 215 of the Federal Power
Act which affords us the opportunity to learn from each other and develop better
answers and solutions that appropriately balance costs, benefits and risks.

Georgia
Transmission
Corporation

R Scott S.
BarfieldMcGinnis

Georgia
System
Operations

February 24, 2011

Negative

Binary severity level for R1 through R5 appears to focus blame for 2003 Black Out
solely on relay loadability and fails to note the 11 other contributing factors to the
cascading black-out (bottom of page 14, "Analysis of Violation Risk Factors and
Violation Severity Levels PRC-023-2 - Transmission Relay Loadability").

Voter

Entity

Segment

Vote

Comment

Corporation

4
Georgia
System
Operations
Corporation
Response: Thank you for your comments.
Guy
Andrews

The drafting team notes that Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. The
drafting team has limited consideration of the role of relay loadability in the August 14, 2003 Northeast Blackout to assigning of VRFs, which
identify the potential reliability significance of noncompliance with each requirement.
Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733, and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are consistent
with that Order.
Gordon
Pietsch

Great River
Energy

Negative

1. R1 criteria 10.1 states that load response transformer fault protection relays
should be set so that the settings do not expose the transformer to a fault
current and duration that exceeds the transformer's mechanical withstand
capability. If load responsive protection needs to have its pickup increased due
to not meeting R1 criteria 10, this amount of load current should not be near
the transformer's mechanical withstand capability. We recommend that the
drafting team add a Rational Box or other supporting documentation that more
clearly explains what the risks are.
2. In addition, we are requesting an expanded description in Measure 1 on what
exactly is required as evidence of calculations performed.

Response: Thank you for your comments.
1. The drafting team agrees that it is possible to set fault protection relays to meet the relay loadability requirement in criterion 10 while
coordinating the relay setting with the mechanical withstand capability. The explanation provided by the drafting team in response to
comments on the previous posting would be an appropriate addition to the Reference Document posted with the standard.
2. The drafting team has listed, within Measure M1, the types of evidence that it feels to be most appropriate to demonstrate compliance with
Requirement R1. However, the drafting team is unable to provide a definitive list of evidence that may be found compliant by the
Compliance Enforcement Authority.
Rex A Roehl

Indeck Energy
Services, Inc.

February 24, 2011

Negative

Assigning only Severe VSL's for R1 - R5 is inappropriate. How can the PC have three
levels of VSL's and an individual, perhaps with a single facility affected by this
standard be in Severe violation. The SDT has avoided the hard questions of what
level applies to what and assigned all to Severe. However important they think this
standard is, not all violations will automatically cause cascading outages or

Voter

Entity

Segment

Vote

Comment
instability.

Response: Thank you for your comments.
The drafting team notes that Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. The
drafting team has limited consideration of the role of relay loadability in the August 14, 2003 Northeast Blackout to assigning of VRFs, which
identify the potential reliability significance of noncompliance with each requirement.
Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733 and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are consistent
with that Order.
Joe D
Petaski

Manitoba
Hydro

Greg C.
Parent

SN
Fernando

Negative

The VSLs for R6 are too severe. The system doesn’t change that rapidly and getting
the list to the entities involved before 60 days does not impact reliability given that
they have 2 years to comply with changes.

Daniel
6
Prowse
Response: Thank you for your comment.
The impact to reliability is not relevant to assigning VSLs. The drafting team notes that Violation Risk Factors (VRFs) identify the potential
reliability significance of noncompliance with each requirement while Violation Severity Levels (VSLs) define the degree to which compliance
with a requirement was not achieved. The drafting team believes that the Severe VSL is appropriate for Requirement R6.
Terry
Harbour

MidAmerican
Energy Co.

Response: Thank you for your comment.

Negative

Nearly all the VSLs are a binary in nature resulting in a zero defect standard with a
“severe” result. This is an incorrect usage of the VSL concept which was to show
graduated levels of risk, not deterministic zero defect results. This incorrect
enforcement concept actually slows reliability progress by delaying standard
implementation and hurts the concept of the new “administrative ticket process”.
FERC will be reluctant to allow the administrative ticket process to be used for a
“severe” VSL violation even if it can be shown there was little to no BES risk.

Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733 and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are consistent

February 24, 2011

Voter

Entity

Segment

Vote

Comment

with that Order.
Christopher
Schneider

MidAmerican
Energy Co.

Negative

Comment:
1. The Attachment B5 criteria determining critical facilities appears to be wide
open and eliminates the facility owner’s authority to determine what are and are
not “critical” facilities on its own system based upon wording in Attachment B.
The word “critical” is used throughout other NERC standards and has many
potential implications. To give one entity, the Planning Coordinator, the power
to assign the designation of “critical” potentially over a facility owners objection
based upon any study or study criteria the Planning Coordinator decides is valid
is inappropriate. Criteria B5 should be deleted. If B5 is not deleted, a minimum,
the B5 wording “in consultation with” should be replaced with “upon mutual
agreement with”. The facility owner who best understands its facilities should
have some final say in conjunction with its Planning Coordinator in determining
what is and is not critical to its system and the region.
2. The drafting team change in Attachment B1 of adding the word “permanent” in
front of “flowgate” did not correct the fundamental issue that a “flowgate” is not
by definition a reliability issue and has no more measurable risk than the loss of
any other BES transmission element. An example is the loss of a 161 kV
flowgate, might have less reliability impact than the loss of a 345 or 500 kV line
that is not designated as a flowgate. Therefore the criteria to define a “critical”
facility through a flowgate designation is fundamentally in error. A better
definition of “critical” is if the loss of a transmission element results in instability,
uncontrolled separation, and cascading as defined in the Federal Power Act.
3. Vote negative on the VSLs Nearly all the VSLs are a binary in nature resulting in
a zero defect standard with a “severe” result. This is an incorrect usage of the
VSL concept which was to show graduated levels of risk, not deterministic zero
defect results. This incorrect enforcement concept actually slows reliability
progress by delaying standard implementation and hurts the concept of the new
“administrative ticket process”. FERC will be reluctant to allow the administrative
ticket process to be used for a “severe” VSL violation even if it can be shown
there was little to no BES risk.

February 24, 2011

Voter

Entity

Segment

Vote

Comment

Facility owner’s input, and in cases where the Facility owner disagrees with the determination of the Planning Coordinator they are free to
use the appeals process in Section 1700 of the NERC Rules of Procedure that was developed to address this concern.
2. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.” This
is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates; specifically, any circuit that is a
monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of that circuit, as confirmed
by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility Rating or to
prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
3. Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733 and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are
consistent with that Order.
Jason L
Marshall

Midwest ISO,
Inc.

Negative

Response: Thank you for your comment.

We disagree with a High VRF for Requirement 6. A High VRF implies there is a direct
coorelation between instability, uncontrolled separation and cascading outages and
a violation of the requirement. In this case, there is not such a coorelation because
another standards requirement violation would have to occur such as operating
above SOLs. At worst, this should have a Medium VRF.

The drafting team believes the VRF for Requirement R6 is appropriate and notes that the reliability objective of Requirement R6 in PRC-023-2 is
the same as Requirement R3 in the FERC approved PRC-023-1: for Planning Coordinators to determine the sub-200 kV facilities for which
responsible entities will be will be subject to the Requirements in the standard. The High VRF for Requirement R6 is consistent with the VRF for
Requirement in PRC-023-1. FERC directed a High VRF in Order 733 noting their expectation for consistency between VRFs assigned to
Requirements that address similar reliability goals. Since the facilities identified by the Planning Coordinator pursuant to Requirement R6 are
required to meet Requirement R1 which is assigned a High VRF, Requirement R6 also has been assigned a High VRF since the reliability
objective of Requirement R1 cannot be achieved if Planning Coordinators do not identify circuits subject to the standard.
Richard Burt

Minnkota
Power Coop.
Inc.

February 24, 2011

Negative

1. 115 kV lines should be included based on the impact they will have on the bulk
system if they trip. Appendix B calls for them to be included if their risk of
overload is above a threshold, regardless of their value to the bulk system.
MPC's 115 kV transmission in northwest Minnesota has 3 principal 230 kV
sources. With two of them outaged per the procedure in Appendix B, we may
very well overload the third source. However, the risk is primarily to the load
served by that 115 kV system, not the surrounding bulk system. By the
procedure in Appendix B (B4a), the 115 kV sources would probably need to
meet the standard, but they should not have to, due to the fact that the at-risk
load is contained within the 115 kV system.
2. There are several places where the standard mandates how entities go about
protecting their equipment so that it is not put at risk. R1 Criteria 10.1 and the

Voter

Entity

Segment

Vote

Comment
related measurement M1 is an example. This goes beyond the reach of NERC. It
is the entity's' prerogative how to protect its equipment.
3. R1 Criteria 5 needs further explanation.
4. R1 Criteria 6 seems too vague. Is it only to be applied to generation that has
one radial tie to the bulk system? What if the generation is injected in the
middle of a long line with no local load, so there are in essence two outlets?
5. In R1 Criteria 12, it appears that the 87% margin should be based on MVA, not
current. Basing it on current appears to compromise the margin.

Response:
1. The Purpose stated in PRC-023 includes ensuring that protective relay settings do not interfere with system operators’ ability to take
remedial action to protect system reliability. While the August 14, 2003 Northeast Blackout was the primary motivation behind
development of the standard, the reliability objective of the standard is not limited to preventing wide-area outages. Smaller scale outages
may impact system reliability and the criteria in Attachment B were developed specifically to address the reliability objective of this
standard. The drafting team believes the criteria in Attachment B will identify circuits that are relevant to the reliability objective of PRC023-2; however, as directed in ¶97 of Order 733, NERC has developed an appeals process so that Facility owners may challenge the
determination of the Planning Coordinators. The appeals process will be contained in Section 1700 of the NERC Rules of Procedure.
2. The standard does not mandate how entities are to protect their equipment. The standard is limited to establishing relay loadability
requirements to prevent circuits from tripping unnecessarily before an operator has time to take corrective action to mitigate the potential
for instability, uncontrolled separation, or cascading outages. In the case of criterion 10.1, the standard does not require the use of load
responsive transformer fault protection relays, it only requires coordination with the mechanical withstand capability of the transformer.
How this coordination is achieved is up to the Facility owner.
3. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Requirement R1,
criterion 5 is unchanged from the approved PRC-023-1. Additional explanation is provided in the Reference Document posted with standard
PRC-023-1.
4. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Requirement R1,
criterion 6 is unchanged from the approved PRC-023-1. Additional explanation is provided in the Reference Document posted with standard
PRC-023-1.
5. Equipment thermal ratings are based on current rather than MVA. Applying the margin to the calculated current is correct as stated.
Saurabh
Saksena

National Grid

February 24, 2011

Affirmative

Voter

Entity

Segment

Vote

Comment

February 24, 2011

However, in attachment B, under Circuits to Evaluate, bullet point 2, the
sentence is missing "...and selected by the Planning Coordinator". This piece is
also missing in 4.2.2.2.
Attachment B, B4 a.: National Grid requests the drafting team to explain the
rationale behind deleting "Category C3" from B4. National Grid believes that by
providing reference to Category C3, the standard focuses on the scope and
provides for consistency in the engineering judgment. However, by deleting
Category C3, the scope becomes undefined as to the level of combinations that
need to be assessed and will concern the engineer that his engineering
judgment can be called into question.
Summary consideration on pg. 1 regarding supervisory elements associated with
current based, communication assisted schemes having to meet PRC-023-2 and
inclusion of such elements in Attachment A, 1.6: This is taken to mean line
differential schemes. If the supervisory elements for a line diff must be set high
enough to comply with PRC-023-2 that will make the entire scheme extremely
insensitive to faults. For example R1.1 would require the supervising elements
be set > 1.5 x the 4 hr. loading meaning the scheme will be unable to detect an
internal fault unless it exceeds 1.5 x the 4 hr. loading. That negates one of the
chief advantages of using a line differential scheme in the first place, specifically
it's sensitivity. If the communications for a relay scheme is lost the scheme is
essentially "broken" and to require it to still function correctly per PRC-023-2
even when broken is unreasonable. There is no requirement that distance
schemes conform to PRC-023-2 if they are broken, for example if they lose their
restraint potential they will trip on load too.
Switch on to fault scheme included in Attachment A, 1.3 - An exception needs
to be added for those schemes that are smart enough to detect a live line
condition and which are disabled when closing or reclosing into an already
energized line. Such schemes will not respond to current flow into and through
a live line. Requiring that such a SOTF scheme that can recognize a live line be
set to carry through current regardless, negates the advantage of the scheme in
the first place, specifically its sensitivity.
Regarding R1, Criterion 10 - What if the transformer at the end of the line has
its own overcurrent protection that either trips a local high side breaker or
circuit switcher or TT's the other end of the source line and this transformer
overcurrent protection is set below the mechanical damage curve. Must the line
protection back at the source to the line still be set below the transformer's
mechanical damage curve? If your answer is yes, what if the line protection is
step distance with a flat timer, like a zone 2 timer. Coordinating a zone 2
looking into the transformer and having a flat zone 2 timer against and inverse

Voter

Entity

Segment

Vote

Comment
transformer mechanical damage curve is awkward at best and maybe not even
feasible.
7. Regarding R1, Criterion 5 - "Weak source system" is a relative term. Is the
reader free to define "weak" as the reader chooses? If not then it needs to be
defined in the standard.

Response: Thank you for your comments.
1. Yes, additional screening will be applied. The Planning Coordinator is required to apply the criteria in Attachment B to these facilities to
identify which circuits on the list are relevant to the reliability objective of PRC-023-2.
2. These differences are intentional. Where the phrase is not included it is referring to the circuits that must be evaluated by the Planning
Coordinator. The Planning Coordinator must apply the criteria in Attachment B to all facilities operated below 100 kV that are on a critical
facilities list. However, the Facility owners are required to comply with PRC-023-2 only for those circuits selected by the Planning
Coordinator in accordance with Requirement R6.
3. The reference to category C3 contingencies resulted in confusion with some entities because the test required in criterion B4 is not the
same as category C3 since criterion B4 does not include manual system adjustments between contingencies.
4. Items included in Section 1.6 of Attachment A are included to address the concerns noted by FERC in Order 733. Settings for the
protection schemes of concern are often very sensitive – well below load current – and dependent on the integrity of the communication
channel to make a trip/no trip decision where other telecommunication system technologies require the operation of other protection
system elements (usually distance elements) which are already subject to the requirements of this standard. Therefore, they will trip
immediately due to load current upon the loss of communications, and are dependent on the fault detectors to inhibit trip which must
therefore be secure regardless of how infrequently loss of communications may occur.
5. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Attachment A, Section
1.3 is unchanged from the approved PRC-023-1. However, the drafting team will include your recommendations in the issues database for
future consideration in the next general revision of the standard.
6. No, in the previous posting the drafting team separated the relay loadability aspect and the transformer fault protection aspect of criterion
10. The transformer fault protection relays and transmission line relays both must meet the relay loadability requirements listed in the two
bullets in criterion 10. Only the transformer fault protection relays, if used, must be coordinated with the transformer mechanical withstand
capability.
7. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Requirement R1,
criterion 5 is unchanged from the approved PRC-023-1. Entities may apply criterion 5 to any line, although when the source becomes
sufficiently strong this criterion will become more restrictive than others.
Michelle
DAntuono

Occidental
Chemical

February 24, 2011

Negative

Need justification as to why the VSLs are listed as Severe.

Voter

Entity

Segment

Vote

Comment

Southern
California
Edison Co.

Negative

Response: Thank you for your comments.

We do not feel that the concerns raised in comments on the last round of balloting
have been adequately addressed. Among the concerns still remaining are the use of
"critical facilities" in several of the requirements and the respective roles that
Regional Entities and Planning Coordinators will play in identifying critical facilities.

The Regional Entity may develop a list of critical facilities by means outside this standard. The reference to a list of critical facilities in PRC-0232 is in the same context as the NERC Statement of Compliance Registry Criteria that provides for excluding from the registration list an entity
that does not own or operate “a transmission element below 100 kV associated with a facility that is included on a critical facilities list that is
defined by the Regional Entity (emphasis added).” To provide additional clarification and alignment with the definition of Bulk Electric System
(BES) presently under development, the drafting team has replaced the reference to a “list of critical facilities” with a reference to transmission
lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are “part of the BES”.
The role of the Planning Coordinator is defined in Requirement R6. The Planning Coordinator will be required to apply the criteria in
Attachment B in accordance with Requirement R6 of PRC-023-2 to identify any circuits on the list for which the Facility owner must comply with
PRC-023-2.
Allan
Morales

Tallahassee
Electric

Affirmative

Heading "Implementation Plan for PRCRPC-023-2:” Transmission Relay Loadability"
has PRC crossed out with RPC in place. Should remain PRC.

Response: Thank you for your comment.
The heading in the Implementation Plan has been corrected.
Ian S Grant
David
Thompson

Tennessee
Valley
Authority

Marjorie S.
Parsons

3
5
6

Negative

the severity level is too great for what is essentially documentation errors
The severity level is too great for what are essentially documentation errors. For
example, for Requirement 7, if the PC takes 31 days to send their critical list to
neighboring RCs and PCs, it should not be a Moderate VSL but something less
severe.

Response: Thank you for your comment.
The drafting team notes that Violation Risk Factors (VRFs) identify the potential reliability significance of noncompliance with each requirement
while Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. For the reporting related
Requirements, R3 through R5, the drafting team believes that the Medium VRF for Requirement R3 and the Lower VRFs for Requirements R4

February 24, 2011

Voter

Entity

Segment

Vote

Comment

and R5 accurately reflect the potential reliability significance of non-compliance. Please note that the Medium VRF for Requirement R3 is
consistent with the FERC approved PRC-023-1. The VSLs for these requirements are based on the VSLs directed in FERC Order 733 for the
FERC approved PRC-023-1. The VSLs are binary because an entity has either provided documentation or it has not, and binary VSLs are Severe
by definition.
Please note that Requirement R7 was removed from the standard prior to the most recent posting to address industry concerns with double
jeopardy.
Gregg R
Griffin

City of Green
Cove Springs

Response: Thank you for your comments.

Negative

From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy of
the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. FMPA suggests changing COM-002-3 R2 to read: Each
Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
to clearly communicate the recipient's understanding of the Reliability Directive..
The term "accuracy" can be interpreted as requiring the recipient to second-guess
the Reliability Directive of the RC to enure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team. For IRO-001-2, FMPA does not
see a need for R1. Doesn't the ERO already have that authority to establish RC's
through the registration process, and to certify system operators through the PER
standards? IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be
better to at least limit the notification to within the same interconnection? Or is R5
truly to identify all NERC registered RC's? More minor comments / suggestions for
improvement: IRO-002 R2 can be improved by replacing "prevent identified events"
with "prevent anticipated events". "Anticipated" aligns better with contingency
analysis than "identified" IRO-005-4 R1 and R2 can be improved by replacing
"expected" with "anticipated". Contingencies are not necessarily "expected";
however, we do "anticipate" them.

It appears that your comments pertain to Project 2006-06 – Reliability Coordination. The formal comment period for Project 2006-06 is open
through March 7, 2011. Please submit your comments through the NERC website.

February 24, 2011

NERC Standards

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User Name

Ballot Results

Ballot Name: 2010-13 Relay Loadability Order Successive Ballot_in

Password

Ballot Period: 1/24/2011 - 2/14/2011
Ballot Type: Initial

Total # Votes: 272

Total Ballot Pool: 324
Quorum: 83.95 % The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
65.71 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.

Home Page
Summary of Ballot Results

Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

97
11
72
21
67
38
0
7
5
6
324

#
Votes

1
0.8
1
1
1
1
0
0.4
0.2
0.5
6.9

#
Votes

Fraction

52
5
33
9
27
17
0
2
1
4
150

Negative
Fraction

0.703
0.5
0.647
0.643
0.711
0.63
0
0.2
0.1
0.4
4.534

Abstain
No
# Votes Vote

22
3
18
5
11
10
0
2
1
1
73

0.297
0.3
0.353
0.357
0.289
0.37
0
0.2
0.1
0.1
2.366

13
1
8
5
12
6
0
2
2
0
49

10
2
13
2
17
5
0
1
1
1
52

Individual Ballot Pool Results

Segment
1
1
1
1
1
1
1
1

Organization

Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
APS
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.

Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Andrew Z Pusztai
Barbara McMinn
Robert D Smith
John Bussman
Scott Kinney

https://standards.nerc.net/BallotResults.aspx?BallotGUID=22e555e1-f701-4677-86ee-9c28cd95b301[2/15/2011 10:31:11 AM]

Ballot
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Comments
View
View
View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Kevin L Howes

Affirmative
Negative

Chang G Choi

Affirmative

Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Gregory Campbell
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Harold Taylor, II
Gordon Pietsch

Negative
Affirmative
Affirmative
Negative
Affirmative

Negative
Negative
Abstain

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative

Robert Solomon

Affirmative

Ajay Garg
Ronald D. Schellberg

Affirmative

Michael Moltane

Affirmative

Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Martyn Turner
Joe D Petaski
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch

Negative
Negative
Negative
Affirmative
Abstain

Randy MacDonald

Affirmative

Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=22e555e1-f701-4677-86ee-9c28cd95b301[2/15/2011 10:31:11 AM]

Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative

View
View

View

View
View
View
View

View
View

View
View
View
View

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Negative
Abstain

View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Anaheim Public Utilities Dept.
APS
Arkansas Electric Cooperative Corporation
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Power Agency
Bonneville Power Administration
Central Lincoln PUD
City of Farmington
City of Green Cove Springs
City of Leesburg
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company

Tim Kelley
Robert Kondziolka
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Long T Duong
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Frank J. Owens
James W. Beck
Keith V Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Kelly Nguyen
Steven Norris
Philip Huff
James V. Petrella
Robert Lafferty
Pat G. Harrington
Duane S Dahlquist
Rebecca Berdahl
Steve Alexanderson
Linda R. Jacobson
Gregg R Griffin
Phil Janik
Michelle A Corley
Bruce Krawczyk
Peter T Yost
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Joe McKinney
Lee Schuster
Anthony L Wilson

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Affirmative
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NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
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3
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4
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5
5

Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Public Power Association
Arkansas Electric Cooperative Corporation
Central Lincoln PUD
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
AEP Service Corp.

R Scott S. Barfield-McGinnis
Sam Kokkinen
David L Kiguel
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
David Burke
Ballard Keith Mutters
John Apperson
Vincent J. Catania
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
Hubert C. Young
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
James R. Keller
Michael Ibold
Kenneth Goldsmith
Allen Mosher
Ronnie Frizzell
Shamus J Gamache
Timothy Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Douglas Hohlbaugh
Henry E. LuBean

Affirmative
Negative
Affirmative
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Negative
Negative
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Negative
Negative
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John D. Martinsen

Abstain

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Edwin B Cano
Brock Ondayko

Affirmative
Abstain

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NERC Standards
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5
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Amerenue
Arizona Public Service Co.
Avista Corp.
Bonneville Power Administration
City and County of San Francisco
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Consolidated Edison Co. of New York
Consumers Energy
Covanta Energy
Cowlitz County PUD
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
El Paso Electric Company
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entergy Corporation
Exelon Nuclear
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MidAmerican Energy Co.
Nebraska Public Power District
New Harquahala Generating Co. LLC
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PPL Generation LLC
Progress Energy Carolinas
Public Service Enterprise Group Incorporated
Public Utility District No. 1 of Lewis County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Sam Dwyer
Edward Cambridge
Edward F. Groce
Francis J. Halpin
Daniel Mason

Negative
Affirmative
Affirmative
Negative
Abstain

Max Emrick

Affirmative

Alan Gale
Stephanie Huffman
Wilket (Jack) Ng
James B Lewis
Samuel Cabassa
Bob Essex
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Alfred W Morgan
Jack Cashin

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Abstain
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Affirmative
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Doug Ramey
Stanley M Jaskot
Michael Korchynsky
David Schumann
Cynthia E Sulzer
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Dennis Florom
Charlie Martin
Mike Laney
S N Fernando
David Gordon
Christopher Schneider
Don Schmit
Nicholas Q Hayes
Gerald Mannarino
Tracy R Bibb
Michael K Wilkerson
Michelle DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Pete Ungerman
Annette M Bannon
Wayne Lewis
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Richard Jones
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Melissa Kurtz
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester
Liam Noailles

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NERC Standards
6
6
6
6
6
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6
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8
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9
10
10
10
10
10
10

AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
INTELLIBIND
JDRJC Associates
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
Oregon Public Utility Commission
Snohomish County PUD No. 1
Utah Public Service Commission
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool Regional Entity
Texas Reliability Entity

Edward P. Cox
Jennifer Richardson
Justin Thompson
Brenda S. Anderson
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P. Mitchell
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Trent Carlson
Claire Warshaw
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Michael C Hill
Marjorie S. Parsons

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Negative
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Negative
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John Stonebarger
David F. Lemmons
Affirmative
James A Maenner
Abstain
Roger C Zaklukiewicz
Affirmative
Edward C Stein
Affirmative
Kevin Conway
Jim D. Cyrulewski
Negative
Brian Evans-Mongeon
Abstain
Terry Volkmann
Negative
William Mitchell Chamberlain
Donald E. Nelson

Negative

Jerome Murray
William Moojen
Ric Campbell
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Stacy Dochoda
Larry D Grimm

Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721

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NERC Standards
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801

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Standards Announcement
Successive Ballot Results
Project 2010-13 - Relay Loadability for Order 733
Now available at: https://standards.nerc.net/Ballots.aspx
A successive initial ballot of PRC-023-2 — Transmission Relay Loadability ended on February 14, 2011.
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results.
Ballot for Standard:
• Quorum: 83.95%
• Approval: 65.71%
Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll Results:
• The poll achieved a quorum with 80% of those who registered to participate provided an opinion; 65%
of those who provided an opinion indicated support for the VRFs and VSLs that were proposed.
Project Background:
When FERC issued Order 733, approving PRC-023-1 — Transmission Relay Loadability, it directed several
changes to that standard and also directed development of one or more new standards within specified time
periods. NERC filed a request for clarification and rehearing, and requested additional time to address the
directives; however, pending FERC’s response to the requests for clarification and additional time, NERC must
progress as though these requests will be denied.
The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases. Phase I
addresses the specific directives from Order 733 that identified required modifications to various elements
within PRC-023-1. Phase II addresses directives associated with development of a new standard to address
generator relay loadability. Phase III addresses directives associated with writing requirements to address
protective relay operations due to power swings. More details may be found on the project page:
http://www.nerc.com/filez/standards/SAR_Project%202010-13_Order%20733%20Relay%20Modifiations.html
Next Steps
The drafting team will consider all comments (those submitted with a comment form and those submitted with a
ballot) and will determine whether to make additional changes to the standard. The team will post its response
to comments and if the standard has only minor changes, will post the standard and conduct a 10-day
recirculation ballot.

Ballot Criteria
Approval requires both (1) a quorum, which is established by at least 75% of the members of the ballot pool
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and non-responses.

Consideration of Comments on Successive Ballot — Relay Loadability Order (Project 2010-13)
Date of Successive Ballot: January 24 – February 14, 2011
Summary Consideration: A 20-day successive ballot was conducted for the Transmission Relay Loadability Version 2 standard PRC-023-2 from
January 24, 2011 to February 14, 2011. The successive ballot achieved a quorum of 83.95% and a weighted segment approval of 65.71%. In
addition to pointing out inconsistencies in the text of the PRC-023-2 standard, which the drafting team acknowledged and revised, commenters
raised concerns in a few technical areas and the drafting team evaluated and responded to these concerns providing clarification and updates to
the standard’s text as noted below Some comments went beyond the scope of the project. The scope of Project 2010-13 is limited to addressing
the FERC directives in Order 733. The drafting team notes that the structure of the standard is unchanged from the approved PRC-023-1 and its
requirements are consistent with the “Zone 3” and “Beyond Zone 3” reviews completed by industry following the August 14, 2003 Northeast
Blackout. Suggested changes to the standard that require further modifications will be evaluated and added to the issues database for future
consideration when making the next set of revisions to PRC-023.
Commenters expressed concern that (in the applicability section of the standard) the Regional Entity is being given additional authority to identify
what equipment operating at or less than 100 kV is critical to the reliable operation of the grid. The drafting team noted that PRC-023 does not
grant the Regional Entity any authority, rather it reflects language already contained in the NERC Statement of Compliance Registry Criteria that
provides for excluding from the registration list entities that do not own or operate “a transmission element below 100 kV associated with a facility
that is included on a critical facilities list that is defined by the Regional Entity.” However, to provide additional clarification and alignment with the
definition of Bulk Electric System (BES) presently under development, the drafting team has modified this reference in the standard to refer to
transmission lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
Commenters were also concerned about the selection of critical facilities according to the criteria in Attachment B and the apparent elimination of
the facility owner’s authority to determine which facilities are or are not included on the critical facilities list. The drafting team pointed out that an
entity may confirm with their Regional Entity whether it has any circuits operated below 100 kV on a list of critical facilities. However, when circuits
operated below 100 kV are identified on such a list, the Planning Coordinator is required to apply the criteria in Attachment B to the list of critical
facilities to determine which circuits on the list are relevant to the reliability objectives of PRC-023-2 and for which the Facility owner must comply
with PRC-023-2. This determination must (i) be based on technical studies or assessments and (ii) must be made in consultation with the Facility
owner. While the drafting team understands the need for Facility owner input, it is also inappropriate to give the Facility Owner de facto veto
power by using the phrase “upon mutual agreement with.” The drafting team believes the Planning Coordinator will give due consideration to the
Facility owner’s input, and in cases where the Facility owner disagrees with the determination of the Planning Coordinator, an appeals process in
Section 1700 of the NERC Rules of Procedure has been developed to address this concern.
Commenters raised concerns about the use of flowgates or permanent flowgates as a criterion to designate a facility as critical from a reliability
perspective. The drafting team noted that the NERC Glossary states that “Total Flowgate Capabilities are determined based on Facility Ratings
and voltage and stability limits.” This is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates;
specifically, any circuit that is a monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of
that circuit, as confirmed by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility
Rating or to prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
Commenters raised concerns regarding the removal of the reference to category C3 contingencies in Attachment B, criterion B4 of PRC-023-2,
which includes the consideration of double contingency events without manual system adjustments between contingencies. The drafting team
indicated that the purpose of the B4 criterion is to determine whether relays must be set to meet loadability requirements such that the circuits will

not be tripped prematurely, resulting in widening of the initiating outage if manual adjustments were not completed before the second contingency.
The test identified in criterion B4 is consistent with, and developed specifically to address, the reliability concern driving the need for this standard.
The drafting team notes that if manual adjustments were allowed between contingencies in criterion B4, this criterion would not identify any circuits
subject to this standard except in cases where TPL-003 is violated. The test appropriately identifies circuits that may be loaded to levels that
challenge relay settings when multiple contingencies occur. The drafting team also clarified that the reference to category C3 contingencies was
removed since it resulted in confusion with some entities because the test required in criterion B4 is not the same as category C3, since criterion
B4 does not include manual system adjustments between contingencies.
Some commenters indicated that there is confusion in the wording regarding Attachment A, Section 1.6 with respect to the listing of those
protective functions that are within the scope of PRC-023-2 and requested clarification. The drafting team acknowledged this confusion and
inserted parenthetical statements to clarify that the phrase “phase overcurrent supervisory elements” refers to phase fault detectors and “currentbased communication-assisted schemes” refers to pilot wire, phase comparison, and line current differential schemes.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
1
Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.

Voter
Kirit S. Shah

Entity
Ameren
Services

Segment
1

Vote
Negative

Comment
(1) We do not agree with the implied establishment of ratings outside of the
requirements of FAC-008 in Requirement R1, criterion 1, which implies the
establishment of a 4 hour rating. Rather than specifically identify the duration, the
term ‘highest seasonal long-term emergency’ rating should be used.
(2) Attachment B Criterion B1 still includes the consideration of flowgates. We
believe that this criterion should be removed from Attachment B.
(3) Attachment B Criterion B4 includes the consideration of double contingency
events without manual system adjustments between contingencies. While the
specific mention of Category C3 contingencies is removed, which would permit
limiting consideration of multiple contingency events to Category C1 bus fault, C2
breaker failure, and C5 common structure outages where no operator intervention
would be possible, such contingency selection would be up to the Planning
Coordinator, not the individual Transmission Owner. As written, the Facility owner
would only have input as to the threshold level against which the post-contingency
loading would be compared, rather than the selection of the multiple contingencies
to be simulated. Any ‘N-1-1’ contingencies should be considered as congestion
issues and should not be considered as part of the criteria in Attachment B for this

The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.

February 24, 2011

Voter

Entity

Segment

Vote

Comment
reliability standard.

Response: Thank you for your comments.
1. The drafting team would understand this concern if the standard required that entities establish 4-hour ratings; however, the drafting team
notes that this criterion intentionally refers to “the available defined loading duration nearest 4 hours” to make it clear that an entity is not
required to develop a 4-hour rating. An entity may use an existing rating, for any time duration, so long as when multiple ratings are
available an entity uses their existing rating that is based on a time duration nearest to 4 hours. This phrase has remained unchanged from
the “Zone 3” and “Beyond Zone 3” reviews completed following the August 14, 2003 Northeast Blackout and is part of the approved
standard PRC-023-1. The drafting team is not aware of any assertion that this criterion establishes a de facto requirement for entities to
develop ratings based on 4-hour duration.
2. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.” This
is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates; specifically, any circuit that is a
monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of that circuit, as confirmed
by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility Rating or to
prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
3. The test identified in criterion B4 is consistent with, and developed specifically to address, the reliability concern driving the need for this
standard. System disturbances in which relay loadability was a contributing factor, such as occurred on August 14, 2003, involve multiple
contingencies without sufficient time for operator action. The drafting team notes that if manual adjustments were allowed between
contingencies in criterion B4, this criterion would not identify any circuits subject to this standard except in cases where TPL-003 is violated.
The test appropriately identifies circuits that may be loaded to levels that challenge relay settings when multiple contingencies occur. When
such circuits are identified the Facility owner is required to meet relay loadability requirements to prevent the circuit from tripping
unnecessarily before an operator has time to take corrective action. The drafting team respectfully points out that the Facility owner is not
required to take any action to prevent overloads from occurring under such circumstances; the Facility owner is required only to provide
relay loadability per the requirements in PRC-023 to mitigate the potential for such N-2 contingencies from leading to instability,
uncontrolled separation, or cascading outages. The drafting team believes that assigning selection of contingencies to the Planning
Coordinator, and requiring Planning Coordinator consultation with the Facility owners regarding evaluation of post-contingency loading, is
consistent with the NERC Functional Model.
Paul B.
Johnson

American
Electric Power

February 24, 2011

Affirmative

The wording of Attachment A, section 1.6 should be made consistent to avoid any
confusion. AEP suggests that it be reworded to read: "Supervisory elements used as
fault detectors associated with pilot wire or current differential protection systems
where the system is capable of tripping for loss of communications".

Voter

Entity

Segment

Vote

Comment

Response: Thank you for your comment.
The drafting team apologizes for confusion regarding Attachment A, Section 1.6 during the previous posting. The drafting team had intended
to provide additional clarification. The drafting team has inserted parenthetical statements to clarify that the phrase “phase overcurrent
supervisory elements” refers to phase fault detectors and “current-based communication-assisted schemes” refers to pilot wire, phase
comparison, and line current differential schemes. We believe this modification is in-line with your recommended modification.
Andrew Z
Pusztai

American
Transmission
Company, LLC

Affirmative

None

Negative

1. BPA believes that there is a major discontinuity in the logical flow of the
standard. As described in Section 4.2, the standard applies to certain
transmission lines and transformers. In Requirement R1, there are thirteen
criteria to select from "for any specific circuit terminal to prevent its phase
protective relay settings from limiting transmission system loadability while
maintaining reliable protection of the BES for all fault conditions". Of these
thirteen criteria, only two apply to transformers--number ten and eleven. The
way that these two are buried in between the other criteria that apply to line
terminals and the way that they are written creates a question as to whether
they apply to all transformers or only to transformers that are part of a
transformer-terminated line. Additionally, since they are part of the group of
thirteen criteria, of which only one must be selected, it appears that criteria ten
and eleven can be ignored if another criterion is selected for a transformerterminated line. BPA forsees this issue causing enough confusion among
auditors and transmission owners that we cannot vote in favor of the standard
until it is remedied. It would clear up the confusion if Criterion 10 was separated
into two parts: one part that deals only with transmission line relays for
transformer-terminated lines, and a second part that deals with load-responsive
transformer relays. The second part--that deals with load-responsive
transformer relays--should be moved along with Criterion 11 into a new
requirement. This way, all of the criteria in Requirement 1 will apply only to line
relays, with only one of the criteria needed to ensure that the line relays will not
limit transmission system loadability. The new requirement (suggest using R2
and bumping the other requirements up a number) would deal specifically with
load responsive transformer relays. Because this requirement would not be

Response: Thank you for your support.

Donald S.
Watkins

Bonneville
Power
Administration

February 24, 2011

Voter

Entity

Segment

Vote

Comment
intermingled among the 13 optional criteria of Requirement 1, it would be clear
that all load responsive transformer relays--not just those for transformerterminated lines--were required to comply.
2. The drafting team has cleared up a major issue with Criterion 10.1 of
Requirement 1 by clarifying that load responsive transformer relays must not
expose a transformer to fault levels and durations that exceed the transformers
mechanical withstand capability. This makes the requirement achievable, while
the earlier version, which required that the relays not expose a transformer to
fault levels and durations that exceeded its capability, was not. However, the
mechanical withstand capability is not a well defined value, and the drafting
team's use of a footnote to clarify this requirement is not sufficient. BPA agrees
with the use of IEEE C57.109-1993 as the best way to define mechanical
withstand capability, but if this is to be used as the measure of this
requirement, it should be written into the requirement and not merely
mentioned as a footnote. In addition, Clause 4.4, Figure 4 of IEEE C57.1091993, as mentioned in the footnote, applies only to Category IV transformers. A
close look at the standard reveals that the mechanical withstand capability
curves for the other categories are not the same, and the requirements for
these other categories must be identified as well.

Response: Thank you for your comments
1. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that the structure of
Requirement R1 is unchanged from the approved PRC-023-1 and is consistent with the “Zone 3” and “Beyond Zone 3” reviews completed
by industry following the August 14, 2003 Northeast Blackout. The drafting team provided additional clarity specific to criterion 10 by
splitting the fault protection aspect directed in the order (now part 10.1) from the relay loadability aspects. The drafting team believes that
combining portions of criteria 10 and 11 at this time would add confusion by intermingling fault protective relays and overload relays.
However, the drafting team will include your recommendations in the issues database for future consideration in the next general revision
of the standard.
2. The drafting team believes that because the reference does not establish a requirement, rather it defines the phrase mechanical withstand
capability, it is most appropriately included as a footnote rather than within Requirement R1, criterion 10. The drafting team also believes
that a general citing of IEEE C57.109 within the requirements would be problematic in that we are only referencing a portion of the
standard. The drafting team notes that the mechanical withstand is well-defined within the standard and that a specific reference to Clause
4.4, Figure from IEEE C57.109-1993 referenced in PRC-023-2 is sufficient. Category IV transformers are defined as transformers over
10,000 kVA (10 MVA) single-phase or 30,000 kVA (30 MVA) three-phase. Since this standard applies to BES facilities, the drafting team
believes that the vast majority (if not all) of the applicable transformers will be Category IV transformers; if any Category III transformers
fall within the applicability of this standard, the associated mechanical characteristic is virtually identical.

February 24, 2011

Voter
Paul Rocha

Entity
CenterPoint
Energy

Segment
1

Vote
Negative

Comment
For the Effective Dates for circuits identified by the Planning Coordinator pursuant to
Requirement R6, CenterPoint Energy is concerned that, as PRC-023-2 is currently
written, these identified circuits will be required to meet the loadability requirements
even though planning-sponsored system improvements completed prior to the
effective dates would alleviate inclusion of the circuit on the list. CenterPoint Energy
would support Draft 2 if the wording “unless system changes, that alleviate inclusion
of the circuit on the list, are completed before the applicable effective date is added
to the end of 5.1.2.1 and 5.2.2.1. For example, 5.1.2.1 would be “The later of the
first day of the first calendar quarter 39 months following notification by the
Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2
per application of Attachment B, or the first day of the first calendar year in which
any criterion in Attachment B applies, unless system changes, that alleviate inclusion
of the circuit on the list, are completed before the applicable effective date.”

Response: The drafting team had intended that if a circuit identified in the near-term planning horizon no longer meets any of the criteria in
Attachment B due to system improvements, the Facility would not be required to comply with the requirements of PRC-023 for that circuit. The
drafting team has added a phrase to the end of 5.1.2.1 and 5.2.2.1 in the Effective Dates section to address your concern, although the
drafting team has omitted the recommended reference to “system changes that alleviate inclusion of the circuit on the list.” This phrase was
omitted to make the modification applicable to any reason for which the Planning Coordinator removes the circuit from the list before the
applicable effective date.
Randall
McCamish

City of Vero
Beach

February 24, 2011

Negative

The Regional Entity is not the correct entity to make decisions concerning what <
100 kV equipment is critical or not. It is too subject to inconsistent criteria being
applied across the continent. It also is not in alignment with the regulatory construct
of a stakeholder process described in Section 215 of the Federal Power Act which
affords us the opportunity to learn from each other and develop better answers and
solutions that appropriately balance costs, benefits and risks. Development of
criteria and the application of that criteria ought to be a collaborative process
continent-wide such that the criteria are applied consistently across the continent.
This can be done separately, or as part of the BES definition effort currently
underway. In the interim, many regions have Planning Coordinators that are not
self-regulating, e.g., the Planning Coordinator is separate from the asset owners.
Most of the Planning Coordinators are stakeholder organization whose "Planning
Committees" would make the determination. For entities that do self-regulate, e.g.,
they are both the asset owner and Planning Coordinator, presumably the Regional
Entity could form a stakeholder process with a Planning Committee whose members
include appropriate and balanced representation from the stakeholders. These
"Planning Committees" could be an alternative source for a stakeholder process to
determine criteria for < 100 kV Applicability and apply that criteria while a

Voter

Entity

Segment

Vote

Comment
continent-wide effort is underway to determine that criteria. These "Planning
Committees" could remain in place to apply the continent-wide criteria to the
regional system.

Response: Thank you for your comment.
The drafting team notes that PRC-023 does not grant the Regional Entity any authority, rather it reflects language already contained in the
NERC Statement of Compliance Registry Criteria that provides for excluding from the registration list entities that do not own or operate “a
transmission element below 100 kV associated with a facility that is included on a critical facilities list that is defined by the Regional Entity
(emphasis added).” However, to provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under
development, the drafting team has modified this reference in the standard to refer to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
Danny
McDaniel

Cleco Power
LLC

Negative

Section 4.2 establishes the conditions to ultimately include the entire electric power
infrastructure under the umbrella of protecting the "bulk electric system" which was
originally defined as 200kV and above. Cleco is concerned this ever expanding
regulatory umbrella is not justified.

Response: Thank you for your comment.
The drafting team believes that Section 4.2 will identify only those circuits that if they trip due to relay loadability, may contribute to undesirable
system performance similar to what occurred during the August 14, 2003 blackout. The criteria developed in Attachment B were developed to
achieve this purpose.
To the extent the commenter is concerned with the reference to facilities operated below 100 kV, the drafting team points out that consistent
with the FERC position in Order 733-A we expect that references to circuits operated below 100 kV will have narrow applicability. The drafting
team also notes that to provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under
development, the drafting team has modified this the reference in the standard to refer to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
Robert
Martinko

FirstEnergy
Energy
Delivery

February 24, 2011

Affirmative

Voter

Entity

Segment

Vote

Comment
sections of PRC-023-2 be revised to include this date: "5.1.1.1.3 For switch-on-tofault schemes as described in PRC-023-2 - Attachment A, Section 1.3, the later of
the first day of the first calendar quarter after applicable regulatory approval of PRC023-2 or the first day of the first calendar quarter 39 months following applicable
regulatory (October 1, 2013 in the U.S.) approval of PRC-023-1; or in those
jurisdictions where no regulatory approval is required, the later of the first day of
the first calendar quarter after Board of Trustees adoption of PRC-023-2 or July 1,
2011." and "5.1.2.1 The later of the first day of the first calendar quarter 39 months
following notification by the Planning Coordinator (October 1, 2013 in the U.S.) of a
circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of
Attachment B, or the first day of the first calendar year in which any criterion in
Attachment B applies.

Response: Thank you for your comments.
The drafting team acknowledges the complexity involved in the effective dates for this standard. The drafting team has reformatted the
Effective Dates section of the standard into a tabular format consistent with CAN-0013 and has inserted the US effective date (October 1, 2013)
where appropriate.
Luther E.
Fair

Gainesville
Regional
Utilities

Negative

Georgia
Transmission
Corporation

February 24, 2011

Affirmative

The hyperlink on page 13 of the draft 3: January 21, 2011 does not work.
Recommendation for future reference: Do not insert hyperlinks in documents.
Instead, place recommended search words to be inserted into the "SEARCH

Voter

Entity

Segment

Vote

Comment
NERC.com" window. That is much less likely to become broken in the future.

Response: Thank you for your comment.
The drafting team has updated the hyperlink and in consideration of your comment has updated the description of the reference document to
facilitate a search if necessary.
Gordon
Pietsch

Great River
Energy

Negative

1. R1 Criteria 10.1 states that load responsive transformer fault protection relays
should be set so that the settings do not expose the transformer to a fault
current and duration that exceeds the transformer’s mechanical withstand
capability. If load responsive protection needs to have its pickup increased due
to not meeting R1 Criteria 10, this amount of load current should not be near
the transformer’s mechanical withstand capability. We recommend that the
drafting team add a Rationale Box or other supporting documentation that more
clearly explains what the risks are.
2. In addition we are requesting an expanded description in Measure 1 on what
exactly is required as evidence of calculations performed.

Response: Thank you for your comments.
The drafting team agrees that it is possible to set fault protection relays to meet the relay loadability requirement in criterion 10 while
coordinating the relay setting with the mechanical withstand capability. The explanation provided by the drafting team in response to
comments on the previous posting would be an appropriate addition to the Reference Document posted with the standard.
Michael
Gammon

Kansas City
Power & Light
Co.

February 24, 2011

Negative

1. The criteria with Attachment B is not consistent with the TPL planning standards
and is likely to identify transmission facilities that do not pose a reliability threat
to the operation of the interconnection. The criteria in Attachment B should
focus on identifying transmission facilities that play a reliability role in
maintaining equipment loadings within SOL and IROL facility ratings and not
include other considerations such as flowgates which are a mechanism for
energy market management.
2. In addition, the implementation time frames specified are not clear whether the
implementation time frame of 24 months is an extension from the 18 month
time frame for the RC to identify circuits using the criteria in Attachment B or if
the 24 months is concurrent with the 18 months. Also, it is uncertain whether
the 24 months will be sufficient without knowing the impact of the RC analysis.

Voter

Entity

Segment

Vote

Comment

Response: Thank you for your comments.
1. The criteria identified in Attachment B are consistent with, and developed specifically to address, the reliability concern driving the need for
this standard. The drafting team continues to believe that Flowgates addressing reliability concerns for loading of circuits is an appropriate
inclusion in these criteria. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage
and stability limits.” This is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates;
specifically, any circuit that is a monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for
loading of that circuit, as confirmed by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent
exceeding the Facility Rating or to prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates
are included for other purposes, criterion B1 would exclude monitored Facilities associated with those Flowgates.
2. The drafting team believes the commenter is referring to the time provided to a Facility owner to comply with PRC-023 after the Planning
Coordinator identifies a circuit is subject to PRC-023-2 per application of Attachment B. The drafting team notes that in the previous
posting of the standard this timeframe was extended from 24 months to 39 months. Specific to the commenter’s question, the standard
identifies the 39 months are measured from “notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B.” The 39 months in neither concurrent with nor an extension of the 18 months provided to the
Planning Coordinator.
Stan T.
Rzad

Keys Energy
Services

February 24, 2011

Negative

Voter

Entity

Segment

Vote

Comment

Manitoba
Hydro

Negative

Please see comments previously submitted by Manitoba Hydro regarding
1. the effective date and
2. the items included in Section 1.6 of Attachment A.

Response: Thank you for your comments.
1. The drafting team has considered a number of comments regarding the implementation timeframe and has extended the implementation
time frame to 39 months to provide the Facility owners time to budget, procure, and install any protection system equipment modifications
and for consistency with PRC-023-1. Extending the timeframe included consideration of the number of circuits that may be identified by
the Planning Coordinator.
2. Items included in Section 1.6 of Attachment A are included to address the concerns noted by FERC in Order 733. Settings for the
protection schemes of concern are often very sensitive – well below load current – and dependent on the integrity of the communication
channel to make a trip/no trip decision where other telecommunication system technologies require the operation of other protection
system elements (usually distance elements) which are already subject to the requirements of this standard. Therefore, they will trip
immediately due to load current upon the loss of communications, and are dependent on the fault detectors to inhibit trip which must
therefore be secure regardless of how infrequently loss of communications may occur.
Terry
Harbour

MidAmerican
Energy Co.

February 24, 2011

Negative

1. The Attachment B5 criteria determining critical facilities appears to be wide
open and eliminates the facility owner’s authority to determine what are and are
not “critical” facilities on its own system based upon wording in Attachment B.
The word “critical” is used throughout other NERC standards and has many
potential implications. To give one entity, the Planning Coordinator, the power
to assign the designation of “critical” potentially over a facility owners objection
based upon any study or study criteria the Planning Coordinator decides is valid
is inappropriate. Criteria B5 should be deleted. If B5 is not deleted, a minimum,
the B5 wording “in consultation with” should be replaced with “upon mutual
agreement with”. The facility owner who best understands its facilities should
have some final say in conjunction with its Planning Coordinator in determining
what is and is not critical to its system and the region.
2. The drafting team change in Attachment B1 of adding the word “permanent” in

Voter

Entity

Segment

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Comment
front of “flowgate” did not correct the fundamental issue that a “flowgate” is not
by definition a reliability issue and has no more measurable risk than the loss of
any other BES transmission element. An example is the loss of a 161 kV
flowgate, might have less reliability impact than the loss of a 345 or 500 kV line
that is not designated as a flowgate. Therefore the criteria to define a “critical”
facility through a flowgate designation is fundamentally in error. A better
definition of “critical” is if the loss of a transmission element results in instability,
uncontrolled separation, and cascading as defined in the Federal Power Act.

Response: Thank you for your comments.
1. The authority for identifying circuits below 200 kV for which Facility owners must comply with PRC-023-2 is assigned to the Planning
Coordinators in PRC-023-1. The drafting team believes that criterion B5 in Attachment B of PRC-023-2 is not wide-open because it requires
that the determination must (i) be based on technical studies or assessments and (ii) must be made in consultation with the Facility owner.
While the drafting team understands the need for Facility owner input, we also believe it is inappropriate to give the Facility Owner de facto
veto power by using the phrase “upon mutual agreement with.” We believe the Planning Coordinator will give due consideration to the
Facility owner’s input, and in cases where the Facility owner disagrees with the determination of the Planning Coordinator they are free to
use the appeals process in Section 1700 of the NERC Rules of Procedure that was developed to address this concern.
2. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.” This
is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates; specifically, any circuit that is a
monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of that circuit, as confirmed
by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility Rating or to
prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
Richard Burt

Minnkota
Power Coop.
Inc.

February 24, 2011

Negative

Voter

Entity

Segment

Vote

Comment
is the entity's' prerogative how to protect its equipment.
3. R1 Criteria 5 needs further explanation.
4. R1 Criteria 6 seems too vague. Is it only to be applied to generation that has
one radial tie to the bulk system? What if the generation is injected in the
middle of a long line with no local load, so there are in essence two outlets?
5. In R1 Criteria 12, it appears that the 87% margin should be based on MVA, not
current. Basing it on current appears to compromise the margin.

Response: Thank you for your comments.
1. The Purpose stated in PRC-023 includes ensuring that protective relay settings do not interfere with system operators’ ability to take
remedial action to protect system reliability. While the August 14, 2003 Northeast Blackout was the primary motivation behind
development of the standard, the reliability objective of the standard is not limited to preventing wide-area outages. Smaller scale outages
may impact system reliability and the criteria in Attachment B were developed specifically to address the reliability objective of this
standard. The drafting team believes the criteria in Attachment B will identify circuits that are relevant to the reliability objective of PRC023-2; however, as directed in ¶97 of Order 733, NERC has developed an appeals process so that Facility owners may challenge the
determination of the Planning Coordinators. The appeals process will be contained in Section 1700 of the NERC Rules of Procedure.
2. The standard does not mandate how entities are to protect their equipment. The standard is limited to establishing relay loadability
requirements to prevent circuits from tripping unnecessarily before an operator has time to take corrective action to mitigate the potential
for instability, uncontrolled separation, or cascading outages. In the case of criterion 10.1, the standard does not require the use of load
responsive transformer fault protection relays, it only requires coordination with the mechanical withstand capability of the transformer.
How this coordination is achieved is up to the Facility owner.
3. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Requirement R1,
criterion 5 is unchanged from the approved PRC-023-1. Additional explanation is provided in the Reference Document posted with standard
PRC-023-1.
4. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Requirement R1,
criterion 6 is unchanged from the approved PRC-023-1. Additional explanation is provided in the Reference Document posted with standard
PRC-023-1.
5. Equipment thermal ratings are based on current rather than MVA. Applying the margin to the calculated current is correct as stated.
Saurabh
Saksena

National Grid

February 24, 2011

Affirmative

Voter

Entity

Segment

Vote

Comment

February 24, 2011

Voter

Entity

Segment

Vote

Comment
looking into the transformer and having a flat zone 2 timer against and inverse
transformer mechanical damage curve is awkward at best and maybe not even
feasible.
7. Regarding R1, Criterion 5 - "Weak source system" is a relative term. Is the
reader free to define "weak" as the reader chooses? If not then it needs to be
defined in the standard.

February 24, 2011

Voter
David
Thorne

Entity
Potomac
Electric Power
Co.

Segment
1

Vote
Negative

Comment
Attachment A of the standard provides a listing of those protective functions that
would be in scope. Presently Section 1.6 of Attachment A is worded as "Supervisory
elements associated with current-based, communication-assisted schemes where
the scheme is capable of tripping for loss of communication." In our comments on
the previous ballot we stated: " The intent of this section was to specifically address
phase overcurrent supervising elements (i.e. phase fault detectors) associated with
pilot wire, phase comparison, and line current differential schemes where the
scheme is capable of tripping for loss of communications. However, we believe that
the term “current-based communication-assisted schemes” is too generic and may
be confusing without mention of the specific schemes to which this requirement
applies....Therefore, to clarify the requirement we suggest replacing the current
wording with either “Phase overcurrent supervisory elements (i.e. phase fault
detectors) associated with pilot wire, phase comparison, and line current differential
schemes, where the scheme is capable of tripping for loss of communications” or
“Phase overcurrent supervisory elements (i.e. phase fault detectors) associated with
current-based communication-assisted schemes (i.e. pilot wire, phase comparison,
and line current differential) where the scheme is capable of tripping for loss of
communications”. The Standard Drafting Team (SDT) responded to our comment by
stating "Attachment A applies to the listed protective functions that respond to load
so it’s unnecessary to use the word “phase”. Section 1.6 has otherwise been
modified essentially as you suggest in response to your comment." There was
another similar comment from AEP with the same SDT response. The SDT did not
modify Section 1.6 using either of our suggestions, since the wording in the current
version remains exactly the same as in the previous version. This may have been an
oversight by the SDT. Without specific identification of what schemes are in scope,
you are leaving up to an auditor to determine what schemes are "current-based"
and what "supervising elements" are you talking about.

Response: Thank you for your comment.
The drafting team apologizes for confusion regarding Attachment A, Section 1.6 during the previous posting. The drafting team had intended
to provide additional clarification. The drafting team has adopted your second proposal and has inserted parenthetical statements to clarify that
the phrase “phase overcurrent supervisory elements” refers to phase fault detectors and “current-based communication-assisted schemes”
refers to pilot wire, phase comparison, and line current differential schemes.
Catherine
Koch

Puget Sound
Energy, Inc.

February 24, 2011

Negative

1. Puget Sound Energy believes this standard is structured in a way that will create
confusion relative to required actions and timelines. For example; Section 4.2.1
Circuits Subject to Requirements R1-R5 This section refers to T-lines and
transformers selected by the Planning Coordinator without any clear criteria to

Voter

Entity

Segment

Vote

Comment
use for the selection which is impossible to comply to.
2. T-lines and Transformers below 100 kV are also applicable if they are included
on a critical facilities list defined by the Regional Entity and selected by the
Planning Coordinator. We have not seen this specific list and do not have any
criteria for our own selection process, which makes this impossible to comply
with.
3. Section 5. Effective Dates This section is confusing with 5 different effective
dates which roll forward when any changes to the standard are made. These
dates also refer to requirements which depend upon lists and selection criteria
that have not been provided by the region.
4. Section PRC-023 Attachment B, Part B4.a, Circuit Identification Criteria
"Simulate double contingency combinations selected by engineering
judgment...." The words Engineering Judgment should not appear in any NERC
standard. The committee chose to replace a reference to TPL 003 Category C3
which was at least something specific. It is impossible to meet compliance with
something as vague as Engineering Judgment.

Response: Thank you for your comments.
1. The criteria for selection by the Planning Coordinator in Applicability Sections 4.2.1.2 and 4.2.1.5 are the same as Sections 4.2.1.3 and
4.2.1.6. These two sections also should have included the phrase “in accordance with Requirement R6” and this clarification has been
added. Thank you for identifying this discrepancy.
2. An entity may confirm with their Regional Entity whether they have any circuits operated below 100 kV on a list of critical facilities. When
circuits operated below 100 kV are identified on such a list, the Planning Coordinator will be required to apply the criteria in Attachment B in
accordance with Requirement R6 of PRC-023-2 to identify any circuits on the list for which the Facility owner must comply with PRC-023-2.
To provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under development, the drafting
team has replaced the reference to a “list of critical facilities” with a reference to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are “part of the BES”.
3. The drafting team acknowledges the complexity involved in the effective dates for this standard. The drafting team has reformatted the
Effective Dates section of the standard into a tabular format to improve clarity.
4. The drafting team notes that similar to the Transmission Planning (TPL) standards, it is not reasonable to require simulation of every
combination of contingencies nor is it possible to provide a bright-line to clearly define which contingencies must be simulated for every
possible system topology. Some level of judgment is necessary to determine the double contingency combinations that must be simulated
to meet the reliability objectives of the standard.

February 24, 2011

Voter
Dana
Cabbell

Entity
Southern
California
Edison Co.

Segment
1

Vote
Negative

Comment
We do not feel that the concerns raised in comments on the last round of balloting
have been adequately addressed. Among the concerns still remaining are the use of
"critical facilities" in several of the requirements and the respective roles that
Regional Entities and Planning Coordinators will play in identifying critical facilities.

Response: Thank you for your comments.
The Regional Entity may develop a list of critical facilities by means outside this standard. The reference to a list of critical facilities in PRC-0232 is in the same context as the NERC Statement of Compliance Registry Criteria that provides for excluding from the registration list an entity
that does not own or operate “a transmission element below 100 kV associated with a facility that is included on a critical facilities list that is
defined by the Regional Entity (emphasis added).” To provide additional clarification and alignment with the definition of Bulk Electric System
(BES) presently under development, the drafting team has replaced the reference to a “list of critical facilities” with a reference to transmission
lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are “part of the BES”.
The role of the Planning Coordinator is defined in Requirement R6. The Planning Coordinator will be required to apply the criteria in
Attachment B in accordance with Requirement R6 of PRC-023-2 to identify any circuits on the list for which the Facility owner must comply with
PRC-023-2.
Larry Akens

Tennessee
Valley
Authority

Affirmative

Permanent flowgate” is too ambiguous. Most entities in the eastern interconnect use
flowgates in many different processes such as EMS systems and state estimator,
transfer capability calculations, congestion management processes, and market
calculations. All of these processes have flowgates that could be considered
“permanent”. If this standard is pointing to the IDC Book of Flowgate (BOF)
Permanent flowgates, then this should be so stated. However, since the IDC BOFs is
not the most up to date list of flowgates, we suggest that a better line criticality
identification to reliability is if a TLR has been called on the flowgate in the last two
year. We recommend that instead of “permanent flowgate”, the B1 portion of
Attachment B1 should say “ in the IDC Book of Flowgates and a TLR 3 or greater
has been called on the flowgate in the last two years

Response: Thank you for your comments.
The drafting team appreciates the suggestion to further refine the Flowgates of interest in the context of criterion B1. However, the drafting
team believes that the Flowgates of interest must be determined based on the reliability basis for adding the Flowgate rather than historical
transfers. Even if a TLR has not been called on a Flowgate for an extended period of time, during a system disturbance an overload on a
monitored Facility comprising the Flowgate could lead to cascading outages if relay loadability requirements are not met. The drafting team
believes it is best to continue to refer to circuits that are monitored Facilities of Flowgates that are included to address reliability concerns for
loading of those circuits.

February 24, 2011

Voter
Keith V
Carman

Entity
Tri-State G &
T Association,
Inc.

Segment
1

Vote
Negative

Comment
1. The response to our concern about Requirement R1, Criterion 10 acknowledges
that 150% of the highest rating of many transformers is 250% of the
transformer’s base rating. Since the transformer thermal damage curve begins
at 200% of the base rating, this requirement can force entities to set relays that
don’t fully protect their transformers. Is Requirement R1, Criterion 13 intended
to be used for those situations? We think it would be more appropriate to
address the concern in Criterion 10 with language to indicate that if the loading
requirement violates thermal protection, then the protection requirement rules
and the relays should be set (with some reasonable margin) to allow as much
loading as possible while ensuring no thermal damage.
2. With regard to requirements R4 and R5, we acknowledge the modifications of
measures M4 and M5 that allows lists of incremental changes to be submitted.
We believe M4 and M5 should be clarified that in the event of no changes, a
submittal is not required or a submittal of “no changes” is acceptable. Periodic
duplicate submittals are unnecessary and unique submittals would more easily
identify the loadability issues that the operators need to consider. The FERC
Order did not require annual submittals.
3. With regard to Attachment B criterion B4, we agree that it is a technically sound
approach but we believe that existing TPL simulations and assessments should
be utilized first to narrow the scope of the analyses. Afterwards, the new
simulation that is described in criterion B4 can be implemented. An example
would be if an element’s loading exceeded 100% of its Facility Rating using the
normal TPL assessment, then the assessment with no manual intervention
would be applied and subsequent steps of criterion B4 would be followed.
4. With regard to Attachment B criterion B5, we acknowledge the modification that
the Facility owner should be consulted. However, we believe that criterion B5
should be removed entirely. We believe that if criteria outside of those in B4 will
be used, they should only be used if mutually agreed upon, which the new B6
expresses. We believe consultation alone does not prevent the criterion from
being applied discriminatorily or differently even within the same
interconnection.

Response: Thank you for your comments.
1. Relays applied for transformer fault protection are subject to Requirement 1, criterion 10. As with any relays applied for fault protection, it
may not be possible to provide thermal protection. Requirement R1, criterion 11 explicitly addresses relays applied for transformer
overload (thermal) protection.
2. Measures M4 and M5 have been updated to indicate that “The updated list may be a full list, a list of incremental changes to the previous
list, or a statement that there are no changes to the previous list”.

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3. The Planning Coordinator is free to apply the criteria in Attachment B in conjunction with analyses performed to demonstrate compliance
with the Transmission Planning (TPL) standards to facilitate efficiency. One option would be for the Planning Coordinator to apply the tests
as described in this comment. The drafting team believes it is best to allow this flexibility without prescriptive language that would lock a
Planning Coordinator into any one approach.
4. The drafting team believes that criterion B5 in Attachment B of PRC-023-2 is appropriate because it requires that the determination must (i)
be based on technical studies or assessments and (ii) must be made in consultation with the Facility owner. While the drafting team
understands the need for Facility owner input, we also believe it is inappropriate to give the Facility Owner de facto veto power by using the
phrase “upon mutual agreement with.” We believe the Planning Coordinator will give due consideration to the Facility owner’s input, and in
cases where the Facility owner disagrees with the determination of the Planning Coordinator they are free to use the appeals process in
Section 1700 of the NERC Rules of Procedure that was developed to address this concern. The situation covered by criterion B6 differs
from criterion B5 in that mutual agreement is required in place of supporting technical studies or assessments.
Brandy A
Dunn

Western Area
Power
Administration

Negative

1. Section B Requirement R1 Criteria 10.1 This should be removed from the
standard. As described in IEEE C57.109-1993, the mechanical damage portion
of the curve applies to frequent faults over the life of the transformer. It may be
necessary, in some cases and for some conditions, to set protective elements
between the mechanical and thermal portion of the damage curve. In these
cases, additional steps such as disabling or limiting automatic reclosing on
neighboring circuits and/or utilizing Operational guidelines can be used to
mitigate possible impacts. NERC should not direct this coordination issue but
instead should leave it up to the Protection Engineer to provide a solution that
fits the situation at hand.
2. Section B Requirement R1 Criteria 11 The second bullet refers to footnote 4
which refers to IEEE standard C57.115. IEEE standard C57.115 has been
withdrawn for some time. The active standard is IEEE C57.91. The NERC
standard needs to refer to active IEEE standards. If IEEE C57.91 does not
support the statement of the second bullet under R1 11 then the NERC standard
should be corrected.

Response: Thank you for your comments.
1. The drafting team disagrees with the commenter’s assessment. The mechanical withstand characteristic in IEEE C57.109 is specifically
characterized as applying for "faults which occur infrequently ..." The IEEE Guide considers that thermal exposure (to frequent faults) is a
phenomena for which the transformer will recover when the thermal condition is relieved, while mechanical exposure (to infrequent faults)
will possibly cause immediate and irrecoverable damage when the transformer's capability is exceeded. While it is true that each entity
should apply their engineering judgment as well as mitigating practices to the application of protective relays, NERC is responsible to
establish standards to prescribe minimum practices which the entities must meet. The drafting team believes that the use of the
mechanical withstand characteristic as proposed in Requirement R1, criterion 10, is an appropriate method of addressing this concern.

February 24, 2011

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2. The drafting team appreciates identification of this issue. The reference has been changed to indicated that IEEE C57.91, Tables 7 and 8
specify that transformers are to be designed to withstand a winding hot spot temperature of 180 degrees C, and that Annex A cautions that
bubble formation may occur above 140 degrees C.
Chuck B
Manning

Electric
Reliability
Council of
Texas, Inc.

Negative

Please reference December 2010 IRC comments.

Response: Thank you for your comment.
The drafting team has reviewed the previous comments and believes we have adequately addressed them within the standard or explained why
modifications to the standard are not warranted.
Kim Warren

Independent
Electricity
System
Operator

Affirmative

We thank the Drafting Team for responding to our comments on the previous
posting. We make the following further suggestions.
1. The Applicability section now includes Section 4.2.2 - Circuits Subject to
Requirement R6. These applicability statements are repeated in Attachment B
with one change to the second bullet where “Transmission lines” has been
replaced by “Lines”. We believe this repetition is unnecessary and has led to
inconsistency observed. In our view a simple reference to Section 4.2.2 would
be sufficient.
2. The DT has introduced the phrase “one-to-five-year planning horizon” in
Criterion B4. We suggest using the defined term “Near-Term Transmission
Planning Horizon” that was developed as part of the recently balloted Project
2010-10: FAC Order 729.

Response: Thank you for your comments.
1. In the most recent posting the drafting team has eliminated much redundancy between the Applicability section, Requirement R6, and
Attachment B. The drafting team acknowledges that repeating the applicability statements in Attachment B is redundant, but believes this
limited amount of redundancy is beneficial in allowing a reader to obtain a complete understanding of the criteria in Attachment B without
the need to refer back to the Applicability section. The drafting team has addressed the discrepancy identified by the commenter and
appreciates identification of this issue.
2. The drafting team appreciates this suggestion, but is reluctant to refer to a defined term until it is included in the NERC Glossary. However,
the drafting team will include your recommendation in the issues database for future consideration in the next general revision of the
standard. If the term is approved at that time, we believe that making the recommended change would be appropriate.

February 24, 2011

Voter
Kathleen
Goodman

Entity
ISO New
England, Inc.

Segment
2

Vote
Negative

Comment
Two issues still remain with this draft:
1. R1.2 still makes no sense and the SDT response did not seem to address our
comment.
2. R4 this is a problem which wasn't in the last version that we commented on.
Now, even if nothing changes, we are required to rerun everything. This seems
a significant use of resources with no Reliability benefit.

Response: Thank you for your comments.
1. Requirement 1 was developed to prevent circuits from tripping unnecessarily before an operator has time to take corrective action.
Recognizing that most entities do not utilize ratings for durations less than 4 hours, the initial criteria developed in response to the August
14, 2003 blackout was based on 150 percent of the Facility Rating nearest 4 hours. Criterion 2 was added to acknowledge that some
entities do utilize a 15-minute rating, and that relay loadability in these cases may be based on this rating. This criterion provides an
alternate method of meeting Requirement R1 when criterion 1 would result in an unrealistic relay loadability requirement (e.g. if a circuit
had a 4-hour rating of 500 MVA and a 15-minute rating of 600 MVA, relay loadability may be based on 1.15 x 600 = 690 MVA instead of
1.5- x 500 = 750 MVA. In some cases this may be the difference between the Facility owner being able to reset the relays versus requiring
a capital project to replace the relays. The drafting team notes that this criterion is unchanged from the “Zone 3” and “Beyond Zone 3”
reviews completed following the August 14, 2003 Northeast Blackout and is part of the approved standard PRC-023-1.
2. The drafting team is confused by the comment since Requirement R4 does not require any analysis to be performed. The updated list
referred to in this requirement is simply a list of circuits for which entities choose to use Requirement R1, criterion 2 to demonstrate relay
loadability. The lists are developed by the Facility Owners and provided to the Planning Coordinator, Transmission Operator, and Reliability
Coordinator.
If the comment is directed toward criterion B4 in Attachment B, the drafting team notes that the footnote explicitly clarifies that when no
material changes occur, past analyses may be used to support the assessment. This removes the burden of repeating past studies to avoid
unnecessary deployment of resources.
Jason L
Marshall

Midwest ISO,
Inc.

Negative

We appreciate the drafting team’s continuing efforts to refine the draft standard but
believe there are still significant issues.
1. We continue to believe that flowgates should not be included in the criteria at
all because they do not usually represent significant reliability issues that might
cause instability, uncontrolled separation or cascading but in fact are primarily
used to manage congestion and to sell transmission service. In response to our
comments from the previous ballot, the drafting team indicated congestion and
system reliability are not mutually exclusive. While we agree on this point, we
disagree on some of their further points. They indicate that the transmission
system is operated within the physical constraints of the transmission system to
prevent instability, uncontrolled separation or cascading. This implies that all

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flowgates are associated with IROLs. This is in fact not the case and most
flowgates are not associated with IROLs. Furthermore, the markets are often
constrained to respect physical limitations such as equipment limits but many
times these are not associated with instability, uncontrolled separation and
cascading. The drafting team further indicates that the IDC is used to preserve
system reliability. This is simply not the case. It is used to manage congestion in
an equitable manner. The FERC in Order 693 specifically prohibited the use of
the IDC to manage IROL constraints because it was not fast enough to prevent
instability, uncontrolled separation and cascading outages. This was also cited in
the August 2003 Blackout Report. Furthermore, this is reflected in IRO-006-4.1
R1.1. Criteria B2 will identify those circuits whose failure could lead to
instability, uncontrolled separation and cascading outages obviating the need to
include flowgates.
2. We do not support criterion B4. It exceeds what is required in the TPL
standards and what is required per the reliability directive in Order 729. The TPL
standards allow system operator intervention for category C3 contingencies
between the two independent Category B contingencies. This standard should
not exceed those requirements in the TPL standards. Paragraphs 79 and 80 of
FERC Order 729 contain the relevant directives regarding the Planning
Coordinator test. Paragraph 79 states that the test “must include or be
consistent with the system simulations and assessments that are required by
the TPL Reliability Standards and meet the system performance levels for all
Category of Contingencies used in transmission planning.” Paragraph 80 states
that “the test must be consistent with the general reliability principles
embedded in the existing series of TPL” standards. Thus, exceeding the TPL
standards could be argued as deviating from the directive. We continue to
believe that if the system as currently designed meets the performance
requirements in TPL-003-0a R1 which allows for operator intervention on
Category C3 contingencies, then the subject facilities would not be included in
the PRC-023-2 R6 list of facilities. For those C3 contingencies that don’t
currently meet the performance obligations after operator interventions, the
subject facilities would be included in the PRC-023-2 R6 list of facilities.
3. We do not believe requirement R4 is needed. Limiting a relay setting to 115%
of the associated transmission line’s highest seasonal 15 minute rating does not
equate to a line that will trip before the operator has time to intervene. It does
not mean the line will trip in 15 minutes. In fact, the operator should be taking
action well in advance of reaching a 15 minute limit and the operator is likely
only using the 15 minute rating in extreme circumstances. Furthermore, the

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operator will have more than 15 minutes to act with a setting 115% above the
15-minute rating.
4. We continue to believe PRC-023-2 R3 and R4 are duplicative of FAC-008-1 and
FAC-009-1. Contrary to the response of the drafting team to the last set of
comments, the communication of facility ratings should include the time
associated with the rating. Thus, if a facility is limited to 15 minutes or 30
minutes or any other finite amount of time, it should be included in the
information communicated about facility ratings. Because FAC-008-1 and FAC009-1 already collectively require the Transmission Owner and Generator Owner
to establish a facilities ratings methodology, rate its facilities consistent with its
methodology and to communicate those ratings and methodology to its
Planning Coordinator, Reliability Coordinator and Transmission Operator, this
information regarding the time associated with the limitation should be
communicated. More specifically FAC-008-1 R1.2.1 requires the Transmission
Owner and Generator Owner to consider relay protective devices in its ratings
methodology. If the drafting team believes communication of additional
information regarding ratings needs to be made clearer, the proper place to
make the refinement would be in FAC-008-1 and FAC-009-1 not in PRC-023.
5. We disagree with the drafting team’s assertion in response to the previous set
of comments that Requirement 5 is an equally effective way to request data as
a Section 1600 data request. First, Section 1600 was specifically written to
collect data and that is its main intent. Ending a Section 1600 data request is
relatively easy as NERC and the Regions could simply stop collecting the data
without any compliance impact on the registered entities. Given the relative
value of this data collection on a long term basis, it is highly likely that NERC
and the Regional Entities will decide at some point that this data is no longer
needed. Secondly, a requirement creates a continuing data request that is
subject to sanctions even if the Regional Entities agree that data is no longer
needed. Further, changing standards is no easy task given the amount of
changes in the queue. The Standards Committee has recently implemented a
prioritization tool and plan to limit work on standards to the top 12 or so
priorities. There is a good chance seeking a change to eliminate a data request
would not be considered a high priority and would result in a significant delay in
terminating the data request. Thirdly, this is an administrative/paper compliance
type of requirement that provides no direct reliability value. It is exactly the type
of requirement that was discussed during the recent FERC Technical Conference
on February 8 and that everyone seemed to agree needs to be prioritized out.
6. Attachment B describes the sub-100 kV facilities that the Planning Coordinator

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must consider in its assessment as those included in the Regional Entities critical
facilities list. We know of no Regional Entity with such a list and there is no
requirement for them to develop such a list. This could create the potential for a
Planning Coordinator to be in violation because the Regional Entity has not
completed its critical facilities list. This is clearly a conflict of interest sine the
Regional Entity also monitors compliance and enforces the standards.

Response: Thank you for your comments.
1. The drafting team acknowledges that reliability-based needs for flowgates include concerns other than preventing instability, uncontrolled
separation, or cascading. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage
and stability limits.” Thus a Flowgate based on Facility Ratings that is not required to prevent instability, uncontrolled separation, or
cascading, but may be based on another reliability need. This is reflected in the text of criterion B1 which is focused on circuits that are
monitored Facilities of Flowgates; specifically, any circuit that is a monitored Facility of a permanent Flowgate, that has been included to
address reliability concerns for loading of that circuit, as confirmed by the applicable Planning Coordinator. Concerns regarding loading of a
circuit may be to prevent exceeding the Facility Rating or to prevent transfer levels that could lead to voltage violations or instability. While
the IDC may be used to manage congestion in an equitable manner, the drafting team maintains that when the need to manage congestion
is based on Facility Ratings or voltage or stability limits, the underlying issue being addressed is system reliability. To the extent that
Flowgates are included for other purposes, criterion B1 would exclude monitored Facilities associated with those Flowgates.
2. The drafting team believes the test in Attachment B achieves the directive in Order 733 (we believe this is the Order to which the
commenter refers) and that deviations from the TPL standards are necessary and appropriate to address concerns stated by FERC, and that
such deviations are not precluded by the Order. Specifically, the test identified in criterion B4 is consistent with, and developed specifically
to address, the reliability concern driving the need for this standard. System disturbances in which relay loadability was a contributing
factor, such as occurred on August 14, 2003, involve multiple contingencies without sufficient time for operator action. The drafting team
notes that if manual adjustments were allowed between contingencies in criterion B4, this criterion would not identify any circuits subject to
this standard except in cases where TPL-003 is violated. The test appropriately identifies circuits that may be loaded to levels that
challenge relay settings when multiple contingencies occur. When such circuits are identified the Facility owner is required to meet relay
loadability requirements to prevent the circuit from tripping unnecessarily before an operator has time to take corrective action. The
drafting team respectfully points out that the Facility owner is not required to take any action to prevent overloads from occurring under
such circumstances; the Facility owner is required only to provide relay loadability per the requirements in PRC-023 to mitigate the potential
for such N-2 contingencies from leading to instability, uncontrolled separation, or cascading outages.
3. Requirement R4 has been included to address the FERC concerns stated in Order 733 and to comply with the associated directive.
Providing this information to the specified entities addresses the potential for confusion as to the amount of time available to take corrective
action.
4. While communicating a Facility Rating would include the time duration associated with the rating, requirements for transmitting the rating
do not include any information as to whether the rating is based on a relay setting. The consequences of exceeding a Facility Rating
typically follow an inverse-time characteristic; however, when a relay loadability limit is exceeded the circuit may trip in time on the order of

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1 second or less, making it important that this information be communicated. Requirements in FAC-008-1 and FAC-009-1 do not require
communication of the information addressed in Requirements R3 and R4 of PRC_023-2. The drafting team further notes that Requirement
R3 is unchanged from the approved PRC-023-1 Requirement R2 (with the exception of minor formatting) and that inclusion of the new
Requirement R4 was directed in Order 733 to addresses stated concerns.
5. The drafting team disagrees with the commenter and reasserts that Requirement R5 is an equally effective way to request this data.
6. The proposed standard requires Planning Coordinators to apply the criteria in Attachment B to all facilities operated below 100 kV that are
on a critical facilities list. The drafting team believes the Planning Coordinator would not be in violation of the standard circuits have been
identified by the Regional Entity and the Planning Coordinator failed to apply the criteria. However, to provide additional clarification and
alignment with the definition of Bulk Electric System (BES) presently under development, the drafting team has modified this reference in
the standard to refer to transmission lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that
are “part of the BES”.
Rebecca
Berdahl

Bonneville
Power
Administration

February 24, 2011

Negative

Voter

Entity

Segment

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Response: Thank you for your comments,
1. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that the structure of
Requirement R1 is unchanged from the approved PRC-023-1 and is consistent with the “Zone 3” and “Beyond Zone 3” reviews completed
by industry following the August 14, 2003 Northeast Blackout. The drafting team provided additional clarity specific to criterion 10 by
splitting the fault protection aspect directed in the order (now part 10.1) from the relay loadability aspects. The drafting team believes that
combining portions of criteria 10 and 11 at this time would add confusion by intermingling fault protective relays and overload relays.
However, the drafting team will include your recommendations in the issues database for future consideration in the next general revision
of the standard.
2. The drafting team believes that because the reference does not establish a requirement, rather it defines the phrase mechanical withstand
capability, it is most appropriately included as a footnote rather than within Requirement R1, criterion 10. The drafting team also believes
that a general citing of IEEE C57.109 within the requirements would be problematic in that we are only referencing a portion of the
standard. The drafting team notes that the mechanical withstand is well-defined within the standard and that a specific reference to Clause
4.4, Figure from IEEE C57.109-1993 referenced in PRC-023-2 is sufficient. Category IV transformers are defined as transformers over
10,000 kVA (10 MVA) single-phase or 30,000 kVA (30 MVA) three-phase. Since this standard applies to BES facilities, the drafting team
believes that the vast majority (if not all) of the applicable transformers will be Category IV transformers; if any Category III transformers
fall within the applicability of this standard, the associated mechanical characteristic is virtually identical.

February 24, 2011

Voter
Gregg R
Griffin

Entity
City of Green
Cove Springs

Segment
3

Vote
Negative

Comment
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy of
the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. FMPA suggests changing COM-002-3 R2 to read: Each
Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
to clearly communicate the recipient's understanding of the Reliability Directive..
The term "accuracy" can be interpreted as requiring the recipient to second-guess
the Reliability Directive of the RC to enure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team. For IRO-001-2, FMPA does not
see a need for R1. Doesn't the ERO already have that authority to establish RC's
through the registration process, and to certify system operators through the PER
standards? IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be
better to at least limit the notification to within the same interconnection? Or is R5
truly to identify all NERC registered RC's? More minor comments / suggestions for
improvement: IRO-002 R2 can be improved by replacing "prevent identified events"
with "prevent anticipated events". "Anticipated" aligns better with contingency
analysis than "identified" IRO-005-4 R1 and R2 can be improved by replacing
"expected" with "anticipated". Contingencies are not necessarily "expected";
however, we do "anticipate" them.

Response: Thank you for your comments. It appears that your comments pertain to Project 2006-06 – Reliability Coordination. The formal
comment period for Project 2006-06 is open through March 7, 2011. Please submit your comments through the NERC website.
Michelle A
Corley

Cleco
Corporation

Negative

February 24, 2011

Voter

Entity

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achieve this purpose.
To the extent the commenter is concerned with the reference to facilities operated below 100 kV, the drafting team points out that consistent
with the FERC position in Order 733-A we expect that references to circuits operated below 100 kV will have narrow applicability. The drafting
team also notes that to provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under
development, the drafting team has modified this the reference in the standard to refer to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
Henry ErnstJr

Duke Energy
Carolina

Affirmative

Duke agrees with the substance of the changes to PRC-023-2, but believe that
compliance questions will arise when entities have to sort out the relationship
between Section 4.2, Requirement R6 and Attachment B Criteria B5 and B6.
Clarifying changes should be made. For example, add the phrase “in accordance
with R6” to 4.2.1.2 and 4.2.1.5, then delete 4.2.2, 4.2.2.1 and 4.2.2.2 entirely, and
finally, change B5 to the way it was in the last draft, and delete B6.

Response: Thank you for your comments.
The drafting team agrees that the phrase “in accordance with R6” should have been included in Applicability Sections 4.2.1.2 and 4.2.1.5 the
same as Sections 4.2.1.3 and 4.2.1.6 and has made this modification. The drafting believes that Section 4.2.2 should remain as this section
differentiates that the set of circuits to which the Planning Coordinator must apply the criteria in Attachment B is a larger set than the set of
circuits for which Facility owners must comply with Requirements R1 through R5 of PRC-023-2.
The drafting team modified criterion B5 to include consultation with the Facility owner to allow the Facility owner an opportunity to provide
insight to the Planning Coordinator performing the analysis. By involving the Facility owner during the Planning Coordinator assessment, the
likelihood that the Facility owner will need to utilize the appeals process in Section 1700 of the NERC Rule of Procedure is reduced.
The drafting team expects that the added criterion B6 will have limited applicability, but it does address a concern raised by commenters during
the previous posting. Given that both parties must mutually agree, the drafting team believes there is no potential for undue compliance
burden as a result of retaining this criterion.
Kevin
Querry

FirstEnergy
Solutions

February 24, 2011

Affirmative

Voter

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Comment
fault schemes as described in PRC-023-2 - Attachment A, Section 1.3, the later of
the first day of the first calendar quarter after applicable regulatory approval of PRC023-2 or the first day of the first calendar quarter 39 months following applicable
regulatory (October 1, 2013 in the U.S.) approval of PRC-023-1; or in those
jurisdictions where no regulatory approval is required, the later of the first day of
the first calendar quarter after Board of Trustees adoption of PRC-023-2 or July 1,
2011." and "5.1.2.1 The later of the first day of the first calendar quarter 39 months
following notification by the Planning Coordinator (October 1, 2013 in the U.S.) of a
circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of
Attachment B, or the first day of the first calendar year in which any criterion in
Attachment B applies."

Kansas City
Power & Light
Co.

Negative

February 24, 2011

Voter

Entity

Segment

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Comment

are included for other purposes, criterion B1 would exclude monitored Facilities associated with those Flowgates.
2. The drafting team believes the commenter is referring to the time provided to a Facility owner to comply with PRC-023 after the Planning
Coordinator identifies a circuit is subject to PRC-023-2 per application of Attachment B. The drafting team notes that in the previous
posting of the standard this timeframe was extended from 24 months to 39 months. Specific to the commenter’s question, the standard
identifies the 39 months are measured from “notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B.” The 39 months in neither concurrent with nor an extension of the 18 months provided to the
Planning Coordinator.
Gregory
David
Woessner

Kissimmee
Utility
Authority

Negative

February 24, 2011

Voter
Greg C.
Parent

Entity
Manitoba
Hydro

Segment
3

Vote
Negative

Comment
Please see comments previously submitted by Manitoba Hydro regarding the
effective date and the items included in Section 1.6 of Attachment A.

MidAmerican
Energy Co.

February 24, 2011

Negative

1. The Attachment B5 criteria determining critical facilities appears to be wide
open and eliminates the facility planner/owner’s authority to determine what are
and are not “critical” facilities on its own system based upon wording in
Attachment B. To give one entity, the Planning Coordinator, the power to assign
the designation of “critical” potentially over a facility planners/owners objection
based upon any study or study criteria the Planning Coordinator decides is valid
is inappropriate and also potentially result in reduced reliability. There may be
issues that the Transmission Planner may know about or know more about that
the Planning Coordinator does not. Criteria B5 should be deleted. If B5 is not
deleted, a minimum, the B5 wording “in consultation with” should be replaced
with “upon mutual agreement with”. The facility planner/owner who best
understands its facilities should have some final say in conjunction with its
Planning Coordinator in determining what is and is not critical to its system and
the region.
2. The drafting team change in Attachment B1 of adding the word “permanent” in
front of “flowgate” did not correct the fundamental issue that a “flowgate” is not
by definition a reliability issue and has no more measurable risk than the loss of
any other BES transmission element. An example is the loss of a 161 kV
flowgate, might have less reliability impact than the loss of a 345 or 500 kV line
that is not designated as a flowgate. Therefore the criteria to define a “critical”
facility through a flowgate designation is fundamentally in error. A better
definition of “critical” is if the loss of a transmission element results in instability,

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uncontrolled separation, and cascading as defined in the Federal Power Act.

Response: Thank you for your comments.
1. The authority for identifying circuits below 200 kV for which Facility owners must comply with PRC-023-2 is assigned to the Planning
Coordinators in PRC-023-1. The drafting team believes that criterion B5 in Attachment B of PRC-023-2 is not wide-open because it requires
that the determination must (i) be based on technical studies or assessments and (ii) must be made in consultation with the Facility owner.
While the drafting team understands the need for Facility owner input, we also believe it is inappropriate to give the Facility Owner de facto
veto power by using the phrase “upon mutual agreement with.” We believe the Planning Coordinator will give due consideration to the
Facility owner’s input, and in cases where the Facility owner disagrees with the determination of the Planning Coordinator, they are free to
use the appeals process in Section 1700 of the NERC Rules of Procedure that was developed to address this concern.
2. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.” This
is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates; specifically, any circuit that is a
monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of that circuit, as confirmed
by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility Rating or to
prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
John S Bos

Muscatine
Power &
Water

Affirmative

How does the STD feel about the possibility of conflicts between the Planning
Coordinator and the Facility Owner pertaining to B5? How would these unforseen
conflicts be resolved?

Response: Thank you for your comment.
As directed in ¶97 of Order 733, NERC has developed an appeals process so that Facility owners may challenge the determination of the
Planning Coordinators. The appeals process will be contained in Section 1700 of the NERC Rules of Procedure.
Michael
Schiavone

Niagara
Mohawk
(National Grid
Company)

February 24, 2011

Affirmative

1. List of Critical Facilities: Since a critical facilities list would be prepared for other
reasons (e.g. CIP-002), National Grid is assuming that the list of critical facilities
will be reviewed for applicability to PRC-023 and that a subset of the list may
need to be defined for this application.
2. There appears to be inconsistency in the wording pertaining to the sentence "critical facilities list defined by the Regional Entity and selected by the Planning
Coordinator". In 4.2.1.3 the aforementioned sentence is produced in its entirety.
However, in attachment B, under Circuits to Evaluate, bullet point 2, the
sentence is missing "...and selected by the Planning Coordinator". This piece is
also missing in 4.2.2.2.
3. Attachment B, B4 a.: National Grid requests the drafting team to explain the
rationale behind deleting "Category C3" from B4. National Grid believes that by

Voter

Entity

Segment

Vote

Comment

February 24, 2011

providing reference to Category C3, the standard focuses on the scope and
provides for consistency in the engineering judgment. However, by deleting
Category C3, the scope becomes undefined as to the level of combinations that
need to be assessed and will concern the engineer that his engineering
judgment can be called into question.
Summary consideration on pg. 1 regarding supervisory elements associated with
current based, communication assisted schemes having to meet PRC-023-2 and
inclusion of such elements in Attachment A, 1.6: This is taken to mean line
differential schemes. If the supervisory elements for a line diff must be set high
enough to comply with PRC-023-2 that will make the entire scheme extremely
insensitive to faults. For example R1.1 would require the supervising elements
be set > 1.5 x the 4 hr. loading meaning the scheme will be unable to detect an
internal fault unless it exceeds 1.5 x the 4 hr. loading. That negates one of the
chief advantages of using a line differential scheme in the first place, specifically
it's sensitivity. If the communications for a relay scheme is lost the scheme is
essentially "broken" and to require it to still function correctly per PRC-023-2
even when broken is unreasonable. There is no requirement that distance
schemes conform to PRC-023-2 if they are broken, for example if they lose their
restraint potential they will trip on load too.
Switch on to fault scheme included in Attachment A, 1.3 - An exception needs
to be added for those schemes that are smart enough to detect a live line
condition and which are disabled when closing or reclosing into an already
energized line. Such schemes will not respond to current flow into and through
a live line. Requiring that such a SOTF scheme that can recognize a live line be
set to carry through current regardless, negates the advantage of the scheme in
the first place, specifically its sensitivity.
Regarding R1, Criterion 10 - What if the transformer at the end of the line has
its own overcurrent protection that either trips a local high side breaker or
circuit switcher or TT's the other end of the source line and this transformer
overcurrent protection is set below the mechanical damage curve. Must the line
protection back at the source to the line still be set below the transformer's
mechanical damage curve? If your answer is yes, what if the line protection is
step distance with a flat timer, like a zone 2 timer. Coordinating a zone 2
looking into the transformer and having a flat zone 2 timer against and inverse
transformer mechanical damage curve is awkward at best and maybe not even
feasible.
Regarding R1, Criterion 5 - "Weak source system" is a relative term. Is the
reader free to define "weak" as the reader chooses? If not then it needs to be

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defined in the standard.

Southern
California
Edison Co.

February 24, 2011

Negative

Voter

Entity

Segment

Vote

Comment

Response: Thank you for your comments.
The Regional Entity may develop a list of critical facilities by means outside this standard. The reference to a list of critical facilities in PRC-0232 is in the same context as the NERC Statement of Compliance Registry Criteria that provides for excluding from the registration list an entity
that does not own or operate “a transmission element below 100 kV associated with a facility that is included on a critical facilities list that is
defined by the Regional Entity (emphasis added).” To provide additional clarification and alignment with the definition of Bulk Electric System
(BES) presently under development, the drafting team has replaced the reference to a “list of critical facilities” with a reference to transmission
lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
The role of the Planning Coordinator is defined in Requirement R6. The Planning Coordinator will be required to apply the criteria in
Attachment B in accordance with Requirement R6 of PRC-023-2 to identify any circuits on the list for which the Facility owner must comply with
PRC-023-2.
Ian S Grant

Tennessee
Valley
Authority

Affirmative

For Attachment B part B1: “Permanent flowgate” is too ambiguous. Most entities in
the eastern interconnect use flowgates in many different processes such as EMS
systems and state estimator, transfer capability calculations, congestion
management processes, and market calculations. All of these processes have
flowgates that could be considered “permanent”. If this standard is pointing to the
IDC Book of Flowgate (BOF) Permanent flowgates, then this should be so stated.
However, since the IDC BOFs is not the most up to date list of flowgates, we
suggest that a better line criticality identification to reliability is if a TLR has been
called on the flowgate in the last two year. We recommend that instead of
“permanent flowgate”, the B1 portion of Attachment B1 should say “ in the IDC
Book of Flowgates and a TLR 3 or greater has been called on the flowgate in the
last two years”.

Consumers
Energy

February 24, 2011

Negative

As a Generator Owner dependent on a Transmission Provider, access to information
about the transmission relays seems to be required for us to comply with this
proposed Standard. It does not seem that the Transmission Provider is required to
furnish us this information. Requiring information transfer without writing it into the
Standard places us in needless jeopardy.

Voter

Entity

Segment

Vote

Comment

Response: Thank you for your comment.
As described in the Applicability section of the standard, Generator Owners are only subject to compliance with Requirements R1 through R5 to
the extent they own load-responsive phase protection systems as described in PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1. If
a Generator Owner owns such relays they should have information available necessary to set the relays and confirm relay loadability
requirements are met.
Frank
Gaffney

Florida
Municipal
Power Agency

Negative

Fort Pierce
Utilities

February 24, 2011

Negative

The Regional Entity is not the correct entity to make decisions concerning what <
100 kV equipment is critical or not. It is too subject to inconsistent criteria being

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Comment
applied across the continent. It also is not in alignment with the regulatory construct
of a stakeholder process described in Section 215 of the Federal Power Act which
affords us the opportunity to learn from each other and develop better answers and
solutions that appropriately balance costs, benefits and risks. Development of
criteria and the application of that criteria ought to be a collaborative process
continent-wide such that the criteria are applied consistently across the continent.
This can be done separately, or as part of the BES definition effort currently
underway. In the interim, many regions have Planning Coordinators that are not
self-regulating, e.g., the Planning Coordinator is separate from the asset owners.
Most of the Planning Coordinators are stakeholder organization whose "Planning
Committees" would make the determination. For entities that do self-regulate, e.g.,
they are both the asset owner and Planning Coordinator, presumably the Regional
Entity could form a stakeholder process with a Planning Committee whose members
include appropriate and balanced representation from the stakeholders. These
"Planning Committees" could be an alternative source for a stakeholder process to
determine criteria for < 100 kV Applicability and apply that criteria while a
continent-wide effort is underway to determine that criteria. These "Planning
Committees" could remain in place to apply the continent-wide criteria to the
regional system.

Illinois
Municipal
Electric
Agency

Negative

Illinois Municipal Electric Agency (IMEA) appreciates the SDT's efforts to include
provisions which distinguish applicability to < 100 kV lines and transformers on a
critical facilities list. IMEA supports comments to this effect as submitted by Florida
Municipal Power Agancy.

February 24, 2011

Voter

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development, the drafting team has modified this reference in the standard to refer to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
Douglas
Hohlbaugh

Ohio Edison
Company

Affirmative

We applaud the drafting team for their diligent and expeditious work on responding
to the FERC directives of Order 733. We support the standard but ask that the team
clarify the effective dates. Compliance Application Notice CAN-0013 which was
recently posted for industry comment correctly adds clarification to the actual
effective date for (1) Transmission lines operated at 100 kV to 200 kV as designated
by the Planning Coordinator as critical to the reliability of the Bulk Electric System;
(2) Transformers with low voltage terminals connected at 100 kV to 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk
Electric System; and (3) Switch-on-to-fault schemes on all applicable facilities. Since
this CAN specifies the date of October 1, 2013 in the U.S., we ask that the following
sections of PRC-023-2 be revised to include this date: "5.1.1.1.3 For switch-on-tofault schemes as described in PRC-023-2 - Attachment A, Section 1.3, the later of
the first day of the first calendar quarter after applicable regulatory approval of PRC023-2 or the first day of the first calendar quarter 39 months following applicable
regulatory (October 1, 2013 in the U.S.) approval of PRC-023-1; or in those
jurisdictions where no regulatory approval is required, the later of the first day of
the first calendar quarter after Board of Trustees adoption of PRC-023-2 or July 1,
2011." and "5.1.2.1 The later of the first day of the first calendar quarter 39 months
following notification by the Planning Coordinator (October 1, 2013 in the U.S.) of a
circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of
Attachment B, or the first day of the first calendar year in which any criterion in
Attachment B applies."

AEP Service
Corp.

February 24, 2011

Affirmative

Voter

Entity

Segment

Vote

Comment

Response: Thank you for your comments.
The drafting team apologizes for confusion regarding Attachment A, Section 1.6 during the previous posting. The drafting team had intended
to provide additional clarification. The drafting team has inserted parenthetical statements to clarify that the phrase “phase overcurrent
supervisory elements” refers to phase fault detectors and “current-based communication-assisted schemes” refers to pilot wire, phase
comparison, and line current differential schemes. We believe this modification is in-line with your recommended modification.
Francis J.
Halpin

Bonneville
Power
Administration

February 24, 2011

Negative

Voter

Entity

Segment

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Comment
the earlier version, which required that the relays not expose a transformer to
fault levels and durations that exceeded its capability, was not. However, the
mechanical withstand capability is not a well defined value, and the drafting
team's use of a footnote to clarify this requirement is not sufficient. BPA agrees
with the use of IEEE C57.109-1993 as the best way to define mechanical
withstand capability, but if this is to be used as the measure of this
requirement, it should be written into the requirement and not merely
mentioned as a footnote. In addition, Clause 4.4, Figure 4 of IEEE C57.1091993, as mentioned in the footnote, applies only to Category IV transformers. A
close look at the standard reveals that the mechanical withstand capability
curves for the other categories are not the same, and the requirements for
these other categories must be identified as well.

Response: Thank you for your comments.
1. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that the structure of
Requirement R1 is unchanged from the approved PRC-023-1 and is consistent with the “Zone 3” and “Beyond Zone 3” reviews completed
by industry following the August 14, 2003 Northeast Blackout. The drafting team provided additional clarity specific to criterion 10 by
splitting the fault protection aspect directed in the order (now part 10.1) from the relay loadability aspects. The drafting team believes that
combining portions of criteria 10 and 11 at this time would add confusion by intermingling fault protective relays and overload relays.
However, the drafting team will include your recommendations in the issues database for future consideration in the next general revision
of the standard.
2. The drafting team believes that because the reference does not establish a requirement, rather it defines the phrase mechanical withstand
capability, it is most appropriately included as a footnote rather than within Requirement R1, criterion 10. The drafting team also believes
that a general citing of IEEE C57.109 within the requirements would be problematic in that we are only referencing a portion of the
standard. The drafting team notes that the mechanical withstand is well-defined within the standard and that a specific reference to Clause
4.4, Figure from IEEE C57.109-1993 referenced in PRC-023-2 is sufficient. Category IV transformers are defined as transformers over
10,000 kVA (10 MVA) single-phase or 30,000 kVA (30 MVA) three-phase. Since this standard applies to BES facilities, the drafting team
believes that the vast majority (if not all) of the applicable transformers will be Category IV transformers; if any Category III transformers
fall within the applicability of this standard, the associated mechanical characteristic is virtually identical.
James B
Lewis

Consumers
Energy

February 24, 2011

Negative

As a Generator Owner dependant on a Transmission Provider, access to information
about the transmission relays seems to be required for us to comply with this
proposed Standard. It does not seem that the Transmission Provider is required to
furnish us this information. Requiring information transfer without writing it into the
Standard places us in needless jeopardy.

Voter

Entity

Segment

Vote

Comment

Indeck Energy
Services, Inc.

Negative

This standard should not apply to generators. To the extent that a particular
generator qualifies for some of the requirements of this standard, they should be
specially applied, as has been done by WECC for generators with long transmission
lines. There are 820 GO and 780 GOP registered entities. It is unlikely that many of
them qualify. It would take an expensive consultant a substantial amount of time to
understand the standard such that a determination could be made for a GO/GOP if
it qualified. This is an unnecessary burden. The applicability section should be
modified as such.

Response: Thank you for your comments.
As described in the Applicability section of the standard, Generator Owners are only subject to compliance with Requirements R1 through R5 to
the extent they own load-responsive phase protection systems as described in PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1.
In order to achieve the reliability objective of this standard, it is necessary for all entities that own such relays to meet the relay loadability
requirements.
Scott
Heidtbrink

Kansas City
Power & Light
Co.

Negative

February 24, 2011

Voter

Entity

Segment

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Comment

and stability limits.” This is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates;
specifically, any circuit that is a monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for
loading of that circuit, as confirmed by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent
exceeding the Facility Rating or to prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates
are included for other purposes, criterion B1 would exclude monitored Facilities associated with those Flowgates.
2. The drafting team believes the commenter is referring to the time provided to a Facility owner to comply with PRC-023 after the Planning
Coordinator identifies a circuit is subject to PRC-023-2 per application of Attachment B. The drafting team notes that in the previous
posting of the standard this timeframe was extended from 24 months to 39 months. Specific to the commenter’s question, the standard
identifies the 39 months are measured from “notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to
PRC-023-2 per application of Attachment B.” The 39 months in neither concurrent with nor an extension of the 18 months provided to the
Planning Coordinator.
SN
Fernando

Manitoba
Hydro

Negative

Please see comments previously submitted by Manitoba Hydro regarding the
effective date and the items included in Section 1.6 of Attachment A.

MidAmerican
Energy Co.

February 24, 2011

Negative

1. Comment: The Attachment B5 criteria determining critical facilities appears to
be wide open and eliminates the facility owner’s authority to determine what
are and are not “critical” facilities on its own system based upon wording in
Attachment B. The word “critical” is used throughout other NERC standards and
has many potential implications. To give one entity, the Planning Coordinator,
the power to assign the designation of “critical” potentially over a facility owners
objection based upon any study or study criteria the Planning Coordinator
decides is valid is inappropriate. Criteria B5 should be deleted. If B5 is not
deleted, a minimum, the B5 wording “in consultation with” should be replaced
with “upon mutual agreement with”. The facility owner who best understands
its facilities should have some final say in conjunction with its Planning

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Comment
Coordinator in determining what is and is not critical to its system and the
region.
2. The drafting team change in Attachment B1 of adding the word “permanent” in
front of “flowgate” did not correct the fundamental issue that a “flowgate” is not
by definition a reliability issue and has no more measurable risk than the loss of
any other BES transmission element. An example is the loss of a 161 kV
flowgate, might have less reliability impact than the loss of a 345 or 500 kV line
that is not designated as a flowgate. Therefore the criteria to define a “critical”
facility through a flowgate designation is fundamentally in error. A better
definition of “critical” is if the loss of a transmission element results in instability,
uncontrolled separation, and cascading as defined in the Federal Power Act.
3. Vote negative on the VSLs Nearly all the VSLs are a binary in nature resulting in
a zero defect standard with a “severe” result. This is an incorrect usage of the
VSL concept which was to show graduated levels of risk, not deterministic zero
defect results. This incorrect enforcement concept actually slows reliability
progress by delaying standard implementation and hurts the concept of the new
“administrative ticket process”. FERC will be reluctant to allow the administrative
ticket process to be used for a “severe” VSL violation even if it can be shown
there was little to no BES risk.

Response: Thank you for your Comments.
1. The authority for identifying circuits below 200 kV for which Facility owners must comply with PRC-023-2 is assigned to the Planning
Coordinators in PRC-023-1. The drafting team believes that criterion B5 in Attachment B of PRC-023-2 is not wide-open because it requires
that the determination must (i) be based on technical studies or assessments and (ii) must be made in consultation with the Facility owner.
While the drafting team understands the need for Facility owner input, we also believe it is inappropriate to give the Facility Owner de facto
veto power by using the phrase “upon mutual agreement with.” We believe the Planning Coordinator will give due consideration to the
Facility owner’s input, and in cases where the Facility owner disagrees with the determination of the Planning Coordinator they are free to
use the appeals process in Section 1700 of the NERC Rules of Procedure that was developed to address this concern.
2. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.” This
is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates; specifically, any circuit that is a
monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of that circuit, as confirmed
by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility Rating or to
prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
3. Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733 and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are

February 24, 2011

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Segment

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Comment

consistent with that Order.

Michelle
DAntuono

Occidental
Chemical

Negative

1. Need justification as to why lines below 100 KV that are included on a critical
facilities list defined by the Regional Entity are also processed through the
Attachment B criteria list. The previous version did not consider lines below
100KV.
2. Attachment B still allows the PC to select facilities below 200KV based on
criteria/studies other than specified in the rest of Attachment B, but requires
this to be done “in consultation with the Facility owner.” This prompts close
scrutiny of the challenge process that is required under the FERC Order. This
also causes Regional discrepancies, which NERC is trying to steer away from.
There should be “bright line” across all Regions.
3. Need justification as to why the VSLs are listed as Severe.
4. There is required annual reporting, which begs the question of what is required
of a Registered Entity that has nothing to report?

Response:
1. The drafting team modified Attachment B in response to industry comments. Based on comments during the previous posting, the drafting
team believes it is appropriate to assess sub-100 kV circuits using the same methodology applied to circuits operated at 100 kV to 200 kV.
Requiring applicable entities to comply for all sub-100 kV circuits included on a critical facilities list defined by the Regional Entity results in
a higher standard for sub-100 kV circuits, and is inconsistent with the directive in ¶60 of Order No. 733.
2. Criteria B1 through B4 in Attachment B provide a consistent methodology for Planning Coordinators to apply across all regions. In
recognition that these criteria may not identify every circuit that presents a risk of cascading outages if relay loadability requirements are
not met, criteria B5 and B6 have been included. The drafting team believes that criteria B1 through B4 will identify the majority of circuits
of concern, and that criteria B5 and B6 will be used only in unique cases that cannot be captured in a bright-line definition.
3. Requirements R1 through R5 are similar in structure to Requirements R1 and R2 in the approved PRC-023-1. FERC directed binary VSLs for
Requirements R1 and R2 in Order 733 and the drafting team believes binary VSLs for Requirements R1 through R5 in PRC-023-2 are
consistent with that Order. In the case of binary VSLs, the VSLs are set to Severe by definition.
4. Measures M4 and M5 have been updated to indicate that “The updated list may be a full list, a list of incremental changes to the previous
list, or a statement that there are no changes to the previous list”.
Sandra L.
Shaffer

PacifiCorp

February 24, 2011

Negative

Voter

Entity

Segment

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Comment
(defined in Attachment A) to which the standard will apply (based on
Attachment B); 3) some combination of the Regional Entity and the Planning
Coordinator are responsible for identifying below 100 kV facilities (defined in
Attachment A) to which the standard will apply (based on Attachment B); and
4) Transmission Owners, Generator Owners, and Distribution Providers that own
the facilities that have been deemed applicable are responsible for complying
with the requirements of the standard. If PacifiCorp’s understanding of these
concepts is generally correct, they must be more clearly stated in PRC-023-2.
2. As is currently drafted, the language contained in the applicability section,
Requirements R6 and R7, and Attachment B are circular, unclear, and
redundant. In order for registered entities to understand their obligations, the
standards must be absolutely clear on what is required and by whom. PacifiCorp
suggests the following: 1) remove R6 because it is redundant with the
Applicability Section 4.2 (or vice versa) and clarify the role of the Planning
Coordinator and the application of Attachment B criteria; 2) Applicability Section
4.2.3 and the second bullet in Attachment B appear to contradict as Section
4.2.3 defines a role for the Planning Coordinator whereas the second bullet in
Attachment B does not - this may be correct for some reason, however, the role
of the Planning Coordinator and the Regional Entity in evaluating facilities below
100 kV must be more clearly defined. PacifiCorp does not have any substantive
issues with the Attachment B criteria. However, in order to be enforceable, the
legal obligations imposed on registered entities under PRC-023-2 must be more
clearly stated.

Response: Thank you for your comment.
1. The understanding described in your first comment are correct, although the drafting team notes that Requirement R7 was removed prior
to posting the standard for comments and concurrent ballot. In addition to removing Requirement R7, the drafting team made a number of
clarifying modifications to the Applicability, Requirement R6, and Attachment B.
2. The commenter has made references to Requirement 7 and to an Applicability section that are not part of the standard that was posted for
comment and concurrent ballot. We believe that the restructured Applicability section and clarifying modifications to Requirement R6 and
Attachment B address the commenter’s concerns related to clarity and circularity.
David
Thompson

Tennessee
Valley
Authority

February 24, 2011

Affirmative

Voter

Entity

Segment

Vote

Comment
flowgates that could be considered “permanent”. If this standard is pointing to the
IDC Book of Flowgate (BOF) Permanent flowgates, then this should be so stated.
However, since the IDC BOFs is not the most up to date list of flowgates, we
suggest that a better line criticality identification to reliability is if a TLR has been
called on the flowgate in the last two year. We recommend that instead of
“permanent flowgate”, the B1 portion of Attachment B1 should say “ in the IDC
Book of Flowgates and a TLR 3 or greater has been called on the flowgate in the
last two years”.

AEP
Marketing

Affirmative

Ameren
Energy
Marketing Co.

Negative

(1) We do not agree with the implied establishment of ratings outside of the
requirements of FAC-008 in Requirement R1, criterion 1, which implies the
establishment of a 4 hour rating. Rather than specifically identify the duration, the
term ‘highest seasonal long-term emergency’ rating should be used.
(2) Attachment B Criterion B1 still includes the consideration of flowgates. We
believe that this criterion should be removed from Attachment B.
(3) Attachment B Criterion B4 includes the consideration of double contingency

February 24, 2011

Voter

Entity

Segment

Vote

Comment
events without manual system adjustments between contingencies. While the
specific mention of Category C3 contingencies is removed, which would permit
limiting consideration of multiple contingency events to Category C1 bus fault, C2
breaker failure, and C5 common structure outages where no operator intervention
would be possible, such contingency selection would be up to the Planning
Coordinator, not the individual Transmission Owner. As written, the Facility owner
would only have input as to the threshold level against which the post-contingency
loading would be compared, rather than the selection of the multiple contingencies
to be simulated. Any ‘N-1-1’ contingencies should be considered as congestion
issues and should not be considered as part of the criteria in Attachment B for this
reliability standard.

Response: Thank you for your comments.
1. The drafting team would understand this concern if the standard required that entities establish 4-hour ratings; however, the drafting team
notes that this criterion intentionally refers to “the available defined loading duration nearest 4 hours” to make it clear that an entity is not
required to develop a 4-hour rating. An entity may use an existing rating, for any time duration, so long as when multiple ratings are
available an entity uses their existing rating that is based on a time duration nearest to 4 hours. This phrase has remained unchanged from
the “Zone 3” and “Beyond Zone 3” reviews completed following the August 14, 2003 Northeast Blackout and is part of the approved
standard PRC-023-1. The drafting team is not aware of any assertion that this criterion establishes a de facto requirement for entities to
develop ratings based on 4-hour duration.
2. As noted in the NERC Glossary, “Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.” This
is reflected in the text of criterion B1 which is focused on circuits that are monitored Facilities of Flowgates; specifically, any circuit that is a
monitored Facility of a permanent Flowgate, that has been included to address reliability concerns for loading of that circuit, as confirmed
by the applicable Planning Coordinator. Concerns regarding loading of a circuit may be to prevent exceeding the Facility Rating or to
prevent transfer levels that could lead to voltage violations or instability. To the extent that Flowgates are included for other purposes,
criterion B1 would exclude monitored Facilities associated with those Flowgates.
3. The test identified in criterion B4 is consistent with, and developed specifically to address, the reliability concern driving the need for this
standard. System disturbances in which relay loadability was a contributing factor, such as occurred on August 14, 2003, involve multiple
contingencies without sufficient time for operator action. The drafting team notes that if manual adjustments were allowed between
contingencies in criterion B4, this criterion would not identify any circuits subject to this standard except in cases where TPL-003 is violated.
The test appropriately identifies circuits that may be loaded to levels that challenge relay settings when multiple contingencies occur. When
such circuits are identified the Facility owner is required to meet relay loadability requirements to prevent the circuit from tripping
unnecessarily before an operator has time to take corrective action. The drafting team respectfully points out that the Facility owner is not
required to take any action to prevent overloads from occurring under such circumstances; the Facility owner is required only to provide
relay loadability per the requirements in PRC-023 to mitigate the potential for such N-2 contingencies from leading to instability,
uncontrolled separation, or cascading outages. The drafting believes that assigning selection of contingencies to the Planning Coordinator,
and requiring Planning Coordinator consultation with the Facility owners regarding evaluation of post-contingency loading, is consistent with

February 24, 2011

Voter

Entity

Segment

Vote

Comment

the NERC Functional Model.

Brenda S.
Anderson

Bonneville
Power
Administration

February 24, 2011

Negative

Voter

Entity

Segment

Vote

Comment
team's use of a footnote to clarify this requirement is not sufficient. BPA agrees
with the use of IEEE C57.109-1993 as the best way to define mechanical
withstand capability, but if this is to be used as the measure of this
requirement, it should be written into the requirement and not merely
mentioned as a footnote. In addition, Clause 4.4, Figure 4 of IEEE C57.1091993, as mentioned in the footnote, applies only to Category IV transformers. A
close look at the standard reveals that the mechanical withstand capability
curves for the other categories are not the same, and the requirements for
these other categories must be identified as well.

Cleco Power
LLC

Negative

February 24, 2011

Voter

Entity

Segment

Vote

Comment

with the FERC position in Order 733-A we expect that references to circuits operated below 100 kV will have narrow applicability. The drafting
team also notes that to provide additional clarification and alignment with the definition of Bulk Electric System (BES) presently under
development, the drafting team has modified this the reference in the standard to refer to transmission lines operated below 100 kV and
transformers with low voltage terminals connected below 100 kV that are “part of the BES.”
Mark S
Travaglianti

FirstEnergy
Solutions

Affirmative

Florida
Municipal
Power Pool

February 24, 2011

Negative

Voter

Entity

Segment

Vote

Comment
criteria and the application of that criteria ought to be a collaborative process
continent-wide such that the criteria are applied consistently across the continent.
This can be done separately, or as part of the BES definition effort currently
underway. In the interim, many regions have Planning Coordinators that are not
self-regulating, e.g., the Planning Coordinator is separate from the asset owners.
Most of the Planning Coordinators are stakeholder organization whose "Planning
Committees" would make the determination. For entities that do self-regulate, e.g.,
they are both the asset owner and Planning Coordinator, presumably the Regional
Entity could form a stakeholder process with a Planning Committee whose members
include appropriate and balanced representation from the stakeholders. These
"Planning Committees" could be an alternative source for a stakeholder process to
determine criteria for < 100 kV Applicability and apply that criteria while a
continent-wide effort is underway to determine that criteria. These "Planning
Committees" could remain in place to apply the continent-wide criteria to the
regional system.

Florida Power
& Light Co.

February 24, 2011

Negative

Objection to including Attachment B, without additional language. Currently, there is
no provision in R6 that explains to the Transmission Owner, Generation Owner or
Distribution Provider their right to challenge a determination under the NERC Rules
of Procedure. Likewise, under the current language, a Planning Coordinator would
have no understanding that its determination could be challenged. Concurrent with
this ballot, NERC is soliciting comments on its new Rules of Procedure Section 1700,
which will explains the challenge process. Hence, without the additional language
proposed below that cross references the Rules of Procedure, PRC-023-2 does not
appear to meet certain essential attributes listed in the NERC Rules of Procedures
Section 302, such as (6) completeness and (8) clear language. Thus, to address this
issue, the following language should be added as a new requirement 6.6: “Pursuant
to Section 1700 of the NERC Rules of Procedure, a Transmission Owner, Generator
or Distribution Provider may challenge a determination (made pursuant to
requirement 6 (and its subparts)) that a facility it owns, in part or whole, is subject

Voter

Entity

Segment

Vote

Comment
to compliance with PRC-023-2.”

Response: Thank you for your comment.
The drafting team notes that it would not be appropriate to include a Requirement 6.6 as proposed by the commenter because the proposed
language is explanatory text and does not create a compliance obligation for any entity. The drafting team also notes that the reference to
Section 302 of the Rules of Procedure is not relevant to including a reference to the appeals process in Section 1700. Note that Completeness
is not at issue because a reference to the appeals process is not necessary to determine the required level of performance and Clear Language
is not at issue because a reference to the appeals process is not required for responsible entities, using reasonable judgment and in keeping
with good utility practices, to arrive at a consistent interpretation. Finally, the drafting team notes that entities have the right to appeal a
decision of the Planning Coordinator regardless of whether such explanatory text is included in PRC-023-2.
Jessica L
Klinghoffer

Kansas City
Power & Light
Co.

Negative

February 24, 2011

Voter

Entity

Segment

Vote

Comment

PRC-023-2 per application of Attachment B.” The 39 months in neither concurrent with nor an extension of the 18 months provided to the
Planning Coordinator.
Daniel
Prowse

Manitoba
Hydro

Negative

Please see comments previously submitted by Manitoba Hydro regarding the
effective date and the items included in Section 1.6 of Attachment A.

Tennessee
Valley
Authority

Affirmative

February 24, 2011

Voter

Entity

Segment

Vote

Comment

loading of those circuits.

Larry D
Grimm

Texas
Reliability
Entity

Negative

1. In R1, criteria 10 and 11, the references to “operator established emergency
transformer rating” should be changed to “owner established emergency
transformer rating” to be consistent with R1. Note that FAC-008 and FAC-009
require the Transmission Owner and Generator Owner entities to establish
Facility Ratings.
2. In R1, criteria 6, 7, 8, and 9, what is the definition of “remote to load”, “remote
from generation stations”, “remote to the system”, and “remote to the bulk
system”? Also, the statement in criteria 7, 8, and 9, “under any system
configuration”, is extremely broad and will be difficult to plan for and enforce.
3. In R3, wording may present a possible conflict with FAC rating methodology, or
should R3 be used as the FAC rating methodology in this case. What is the form
of agreement required from the Planning Coordinator, Transmission Operator,
and RC?
4. In R5, the TO, GO, and DP should also provide the updated list of circuits to the
Transmission Planner, Planning Coordinator, and Reliability Coordinator as well
as the Regional Entity.
5. Attachment A, Item 2. Consider including current differential protection systems
that are designed to respond only to internal fault conditions and not overload
conditions in the list of systems that are excluded from this standard.
6. Attachment B, B3. NUC-001 uses Generator Operator instead of plant owner.
7. Attachment B, B4.b. Suggest rewording as follows “For circuits operated
between 100 kV and 200 kV, evaluate the post-contingency loading after
contingency evaluations per TPL-003, Category A, B, and C3, in consultation
with the Facility owner, against a threshold based on the Facility Rating
assigned for that circuit and used in the power flow case by the Planning
Coordinator.”

Response: Thank you for your comments.
1. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that the phrase “operator
established emergency transformer rating” is unchanged from the approved PRC-023-1. The drafting team will include your
recommendation in the issues database for future consideration in the next general revision of the standard.
2. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team notes that Requirement R1,
criteria 7, 8, and 9 are unchanged from the approved PRC-023-1. Additional explanation is provided in the Reference Document posted
with standard PRC-023-1.

February 24, 2011

Voter

Entity

Segment

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Comment

3. When an entity uses criterion 6, 7, 8, 9, 12, or 13 as the basis for verifying transmission line relay loadability, Requirement R3 should be
used as the rating methodology for the relevant circuits. Agreement of the Planning Coordinator, Transmission Operator, and Reliability
Coordinator can be documented by evidence such as dated correspondence as noted in Measure M3. The drafting team will request this
issue be added to the Issues Database for the FAC standards at such time they are to be revised.
4. The purpose of providing the information to the Regional Entity is for the ERO to make this information available, upon request, to users,
owners, and operators of the Bulk Electric System, and directed in ¶224 of Order 733. The drafting team believes the proposed change is
unnecessary since the Transmission Planner, Planning Coordinator, and Reliability Coordinator can request this information from the ERO.
5. The scope of Project 2010-13 is limited to addressing the FERC directives in Order 733. The drafting team will include your
recommendation in the issues database for future consideration in the next general revision of the standard.
6. Plant owner has been changed to Generator Operator for consistency with NUC-001 as recommended by the commenter.
7. The drafting team believes that it is unnecessary to include Category A and B contingencies in criterion B4 since the loading would not
exceed the Facility Rating except in cases of non-compliance with NERC Reliability Standards TPL-001 and TPL-002. Similarly, the drafting
team has previously removed the reference to Category C contingencies because it resulted in confusion with some entities because the
test required in criterion B4 is not the same as Category C3. The test specified in criterion B4 does not include manual system adjustments
between contingencies. The drafting team notes that if manual adjustments were allowed between contingencies in criterion B4, this
criterion would not identify any circuits subject to this standard except in cases where TPL-003 is violated.

END OF REPORT

February 24, 2011

Implementation Plan for PRC-023-2: Transmission Relay Loadability
1. Standards Involved